Exhibit 99.1

Report of Independent Registered Public Accounting Firm

The Partners
Crosstex Energy GP, L.P.:

     We have audited the accompanying consolidated balance sheet of Crosstex Energy GP, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 2008. This consolidated financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this consolidated financial statement based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit of a balance sheet includes examining, on a test basis, evidence supporting the amounts and disclosures in that balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

     In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Crosstex Energy GP, L.P. and subsidiaries as of December 31, 2008, in conformity with U.S. generally accepted accounting principles.

		/s/ KPMG LLP

Dallas, Texas
March 2, 2009

CROSSTEX ENERGY GP, L.P.
Consolidated Balance Sheet
December 31, 2008
(In thousands)

ASSETS

Current assets:
Cash and cash equivalents		$	1,636
Accounts receivable:
Trade, net of allowance for bad debts of $3,655			49,185
Accrued revenues			292,668
Imbalances			3,893
Affiliated companies			110
Note receivable			375
Other			7,243
Fair value of derivative assets			27,166
Natural gas and natural gas liquids, prepaid expenses, and other			9,645
Total current assets			391,921
Property and equipment:
Transmission assets			474,771
Gathering systems			614,572
Gas plants			577,250
Other property and equipment			70,618
Construction in process			86,462
Total property and equipment			1,823,673
Accumulated depreciation			(296,393	)
Total property and equipment, net			1,527,280
Fair value of derivative assets			4,628
Intangible assets, net of accumulated amortization of $89,231			578,096
Goodwill			19,673
Other assets, net			11,668
Total assets		$	2,533,266
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Drafts payable		$	21,514
Accounts payable			23,879
Accrued gas purchases			270,229
Accrued imbalances payable			7,100
Fair value of derivative liabilities			28,506
Current portion of long-term debt			9,412
Other current liabilities			64,191
Total current liabilities			424,831
Long-term debt			1,254,294
Other long-term liabilities			24,708
Deferred tax liability			8,727
Fair value of derivative liabilities			22,775
Minority Interest			781,126
Commitments and contingencies			—
Partners’ equity			16,805
Total liabilities and partners’ equity		$	2,533,266

See accompanying notes to consolidated balance sheet.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(1) Organization and Summary of Significant Agreements

(a)

Description of Business

     Crosstex Energy GP, L.P. (the General Partner) is a Delaware limited partnership formed on July 12, 2002 to become the General Partner of Crosstex Energy, L.P. The General Partner is an indirect wholly-owned subsidiary of Crosstex Energy, Inc. (CEI). The General Partner owns a 2% general partner interest in Crosstex Energy, L.P. (CELP). CELP is engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids or NGLs. CELP 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, transports natural gas and NGLs and ultimately provides an aggregated supply of natural gas and NGLs to a variety of markets. In addition, CELP 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.

(b)

Partnership Ownership

     Crosstex Energy GP, L.P., the general partner of the Partnership, is an indirect wholly-owned subsidiary of Crosstex Energy, Inc. (CEI). As of December 31, 2008, CEI owns 16,414,830 common units in the Partnership through its wholly-owned subsidiaries. As of December 31, 2008, CEI owned 34.0% of the limited partner interests in the Partnership and officers and directors owned 1.02% of the limited partnership interests. The remaining units are held by the public.

(c)

Basis of Presentation

     The accompanying consolidated balance sheet includes the assets and liabilities of operations of the General Partner and CELP. The General Partner has no independent operations and no material assets outside of its interest in CELP. The General Partner proportionately consolidates CELP’s undivided 59.27% interest in a gas plant acquired by CELP in November 2005 (23.85%) and May 2006 (35.42%). The General Partner also consolidates CELP’s joint venture interest in Crosstex DC Gathering, J.V. (CDC) as discussed more fully in Note 3, in accordance with FASB Interpretation No. 46R, Consolidation of Variable Interest Entities (FIN No. 46R). The consolidated operations are hereafter referred to herein collectively as the “Partnership.” All material intercompany balances and transactions have been eliminated.

(2) Significant Accounting Policies

(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)

Cash and Cash Equivalents

     The Partnership considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c)

Natural Gas and Natural Gas Liquids Inventory

     The Partnership’s inventories of products consist of natural gas and NGLs. The Partnership reports these assets at the lower of cost or market.

(d)

Property, Plant, and Equipment

     Property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, industrial supply pipelines, NGL pipelines, natural gas processing plants, NGL fractionation plants, dew point control and gas treating plants.

     Other property and equipment is primarily comprised of computer software and equipment, furniture, fixtures, leasehold improvements and office equipment. Property, plant and equipment are recorded at cost. Gas required to maintain pipeline minimum

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

pressures is capitalized and classified as property, plant and equipment. Repairs and maintenance are charged against income when incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. Interest costs are capitalized to property, plant and equipment during the period the assets are undergoing preparation for intended use.

     Depreciation is provided using the straight-line method based on the estimated useful life of each asset, as follows:

		Useful Lives
Transmission assets		15-30 years
Gathering systems		7-15 years
Gas treating and gas processing plants		15 years
Other property and equipment		3-10 years

     Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires long-lived assets to be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. In order to determine whether an impairment has occurred, the Partnership compares the net book value of the asset to the undiscounted expected future net cash flows. If impairment has occurred, the amount of such impairment is determined based on the expected future net cash flows discounted using a rate commensurate with the risk associated with the asset.

     When determining whether impairment of one of our long-lived assets has occurred, the Partnership must estimate the undiscounted cash flows attributable to the asset. The Partnership’s estimate of cash flows is based on assumptions regarding the purchase and resale margins on natural gas, volume of gas available to the asset, markets available to the asset, operating expenses, and future natural gas prices and NGL product prices. The amount of availability of gas to an asset is sometimes based on assumptions regarding future drilling activity, which may be dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors. Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

     The Partnership recorded impairments to long-lived assets of $25.6 million during the year ending December 31, 2008. No impairments were incurred during the years ended December 31, 2007 and 2006.

     Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, also requires long-lived assets being held for sale or disposed of to be presented in the financial statements separately. During the third quarter of 2008 the Partnership held for sale its undivided 12.4% interest in the Seminole gas processing plant. The sale was finalized on November 17, 2008.

     During 2008 CEI transferred the Clarkson and Jonesville plants to the Partnership at net book value for a cash price of $0.4 million which represented the fair value of the plants.

(e)

Goodwill and Intangibles

     The Partnership has approximately $19.7 million of goodwill at December 31, 2008. Goodwill created in the formation of the Partnership of $4.9 net book value associated with the Midstream assets was impaired during the year ended December 31, 2008. The goodwill remaining in the Partnership is associated with the Treating assets. Goodwill will continue to be assessed at least annually for impairment.

     Intangible assets consist of customer relationships and the value of the dedicated and non-dedicated acreage attributable to pipeline, gathering and processing systems. The Chief acquisition, included $395.6 million of such intangibles, including the Devon Energy Corporation (Devon) gas gathering agreement. Intangible assets other than the intangibles associated with the Chief acquisition are amortized on a straight-line basis over the expected period of benefits of the customer relationships, which range from three to 15 years. The intangible assets associated with the Chief acquisition are being amortized using the units of throughput method of amortization.

(f)

Other Assets

     Unamortized debt issuance costs totaling $11.7 million at December 31, 2008 are included in other noncurrent assets. Debt issuance costs are amortized into interest expense using the effective-interest method over the term of the debt for the senior secured

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

notes. Debt issuance costs are amortized using the straight-line method over the term of the debt for the bank credit facility because borrowings under the bank credit facility cannot be forecasted for an effective-interest computation.

(g)

Gas Imbalance Accounting

     Quantities of natural gas over-delivered or under-delivered related to imbalance agreements are recorded monthly as receivables or payables using weighted average prices at the time of the imbalance. These imbalances are typically settled with deliveries of natural gas or NGLs. The Partnership had imbalance payables of $7.1 million at December 31, 2008 which approximates the fair value of these imbalances. The Partnership had imbalance receivables of $3.9 million at December 31, 2008 which are carried at the lower of cost or market value.

(h)

Asset Retirement Obligations

     In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which became effective at December 31, 2005. FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, "Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement activity should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB Statement No. 143. The Partnership did not provide any asset retirement obligations as of December 31, 2008 because it does not have sufficient information as set forth in FIN 47 to reasonably estimate such obligations and the Partnership has no current intention of discontinuing use of any significant assets.

(i)

Revenue Recognition

     The Partnership recognizes revenue for sales or services at the time the natural gas, or NGLs are delivered or at the time the service is performed. The Partnership generally accrues one to two months of sales and the related gas purchases and reverses these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates. The Partnership’s purchase and sale arrangements are generally reported in revenues and costs on a gross basis in the statements of operations in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee based arrangements and the Partnership’s energy trading activities related to its “off-system” gas marketing operations discussed in Note 2(k), the Partnership acts as the principal in these purchase and sale transactions, has the risk and reward of ownership as evidenced by title transfer, schedules the transportation and assumes credit risk.

     The Partnership accounts for taxes collected from customers attributable to revenue transactions and remitted to government authorities on a net basis (excluded from revenues).

(j)

Derivatives

     The Partnership uses derivatives to hedge against changes in cash flows related to product price and interest rate risks, as opposed to their use for trading purposes. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, requires that all derivatives be recorded on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the differences between the derivative’s fixed contract price and the underlying market price at the determination date. The asset or liability related to the derivative instrument is recorded on the balance sheet as fair value of derivative assets or liabilities.

     Realized and unrealized gains and losses on derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, are recorded as gain or loss on derivatives in the consolidated statement of operations. Unrealized gains and losses on effective cash flow derivatives are recorded as a component of accumulated other comprehensive income. When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transformed from accumulated other comprehensive income to earnings. Realized gains and losses on commodity hedge derivatives are recognized in revenues, and realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Settlements of derivatives are included in cash flows from operating activities.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(k)

Legal Costs Expected to be Incurred in Connection with a Loss contingency

     Legal costs incurred in connection with a loss contingency are expensed as incurred.

(l)

Income Taxes

     The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The net tax basis in the Partnership’s assets and liabilities is less than the reported amounts on the financial statements by approximately $437.2 million as of December 31, 2008. Effective January 1, 2007, the Partnership is subject to the margin tax enacted by the state of Texas on May 1, 2006.

     The LIG entities the Partnership formed to acquire the stock of LIG Pipeline Company and its subsidiaries, are treated as taxable corporations for income tax purposes. The entity structure was formed to effect the matching of the tax cost to the Partnership of a step-up in the basis of the assets to fair market value with the recognition of benefits of the step-up by the Partnership. A deferred tax liability of $8.2 million was recorded at the acquisition date. The deferred tax liability represents future taxes payable on the difference between the fair value and tax basis of the assets acquired. The Partnership, through ownership of the LIG entities, generated a net operating loss of $4.8 million during 2005 as a result of a tax loss on a property sale of which $0.9 million was carried back to 2004, $1.9 million was utilized in 2006 and substantially all of the remaining $2.0 million was utilized in 2007.

     The Partnership provides for income taxes using the liability method. The principal component of the Partnership’s net deferred tax liability is as follows of December 31, 2008 (in thousands):

Deferred income tax assets:
Net operating loss carryforward — current		$	41
Net operating loss carryforward — long-term			—
Alternative minimum tax credit carryover — long-term			—
		$	41
Deferred income tax liabilities:
Property, plant, equipment, and intangible assets-current.		$	(501	)
Property, plant, equipment and intangible assets-long-term			(8,727	)
			(9,228	)
Net deferred tax liability		$	(9,187	)

     A net current deferred tax liability of $0.5 million is included in other current liabilities.

     The Partnership adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007. A reconciliation of the beginning and ending amount of the unrecognized tax benefits is as follows (in thousands):

Balance as of December 31, 2007		$	—
Increases related to prior year tax positions			904
Increases related to current year tax positions			717
Balance as of December 31, 2008		$	1,621

     Unrecognized tax benefits of $1.6 million, if recognized, would affect the effective tax rate. We do not expect any material change in the balance of our unrecognized tax benefits over the next twelve months. In the event interest or penalties are incurred with respect to income tax matters, our policy will be to include such items in income tax expense. At December 31, 2008, tax years 2005 through 2008 remain subject to examination by the Internal Revenue Service and applicable states.

(m)

Environmental Costs

     Environmental expenditures are expensed or capitalized as appropriate, depending on the nature of the expenditures and their future economic benefit. Expenditures that related to an existing condition caused by past operations that do not contribute to current or future revenue generation are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (or discounted when the obligation can be settled at fixed and determinable amounts) when environmental assessments or clean-ups are probable and the costs can be reasonably estimated.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(n)

Cash Distributions

     Unless restricted by the terms of our credit facility, CELP 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. CELP’s senior secured credit facility prohibits CELP from declaring distributions to unitholders if any event of default exists or would result from the declaration of distributions.

     Under the quarterly incentive distribution provisions, generally the General Partner is entitled to 13% of amounts CELP distributes in excess of $0.25 per unit, 23% of the amounts CELP distributes in excess of $0.3125 per unit and 48% of amounts CELP distributes in excess of $0.375 per unit. Incentive distributions totaling $30.8 million were earned by the General Partner for the year ended December 31, 2008. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter. CELP paid annual per common unit distributions of $2.28 for the year ended December 31, 2008.

     See Note (4) for a description of the bank credit facilities, which restrict the Partnership’s ability to make future distributions.

(o)

Minority Interest

     Minority interest represents third party ownership interests in the net assets of our subsidiaries that primarily include the limited partners of CELP and CELP’s joint venture partner. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third party ownership interest in such amounts presented as minority interest.

(p)

Option Plans

     Effective January 1, 2006, the Partnership adopted the provisions of SFAS No. 123R, "Share-Based Payment” (FAS No. 123R) which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.

     The Partnership elected to use the modified-prospective transition method for adopting SFAS No. 123R. Under the modified-prospective method, awards that are granted, modified, repurchased, or canceled after the date of adoption are measured and accounted for under SFAS No. 123R. The unvested portion of awards that were granted prior to the effective date are also accounted for in accordance with SFAS No.123R. Under SFAS No.123R, the Partnership is required to estimate forfeitures in determining periodic compensation cost.

     The Partnership and CEI each have similar unit or share-based payment plans for employees. 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 interest in the Partnership.

(q)

Recent Accounting Pronouncements

     In June 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 shares with nonforfeitable dividend rights in the calculation of earnings per share 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) 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

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

between the different measurement attributes elected for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 will have no 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 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 May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS No. 162”). SFAS No. 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States of America. SFAS No. 162 will be effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 162 on our consolidated financial statements.

     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.

(3) Investment in Joint Venture and Note Receivable

     The Partnership owns a majority interest in Crosstex Denton County Joint Venture (CDC) and consolidates its investment in CDC pursuant to FIN No. 46R. The Partnership manages the business affairs of CDC. The other joint venture partner (the CDC partner) is an unrelated third party who owns and operates a natural gas field located in Denton County, Texas.

     In connection with the formation of CDC, the Partnership agreed to loan the CDC partner up to $1.5 million for its initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC partner’s share of distributable cash flow to repay the loan. The balance remaining on the note of $0.4 million is included in current notes receivable as of December 31, 2008.

(4) Long-Term Debt

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

Bank credit facility, interest based on Prime or LIBOR plus an applicable margin, interest rate at December 31, 2008 was 6.33%		$	784,000
Senior secured notes, weighted average interest rate at December 31, 2008 of 8.0%			479,706
			1,263,706
Less current portion			(9,412	)
Debt classified as long-term		$	1,254,294

     Credit Facility. In September 2007, the Partnership increased borrowing capacity under the bank credit facility to $1.185 billion. The bank credit facility matures in June 2011. As of December 31, 2008, $850.4 million was

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

outstanding under the bank credit facility, including $66.4 million of letters of credit, leaving approximately $334.6 million available for future borrowing.

     Obligations under the bank credit facility are secured by first priority liens on all of the Partnership’s material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the Partnership’s equity interests in substantially all of its subsidiaries, and rank pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by the Partnership’s material subsidiaries. The Partnership may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.

     On November 7, 2008, the Partnership entered into the Fifth Amendment and Consent (the “Fifth Amendment”) to its credit facility with Bank of America, N.A., as administrative agent, and the banks and other parties thereto (the “Bank Lending Group”). The Fifth Amendment amended the agreement governing its credit facility to, among other things, (i) increase the maximum permitted leverage ratio it must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009, (ii) lower the minimum interest coverage ratio it must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter, (iii) permit it to sell certain assets, including the non-strategic asset dispositions (iv) increase the interest rate it pays on the obligations under the credit facility and (v) lower the maximum permitted leverage ratio it must maintain if the Partnership or its subsidiaries incur unsecured note indebtedness.

     Due to the continued decline in commodity prices and the deterioration in the processing margins, the Partnership determined that there was a significant risk that the amended terms negotiated in November 2008 would not be sufficient to allow it to operate during 2009 without triggering a default under its bank facility and the senior secured note agreement. On February 27, 2009, the Partnership entered into the Sixth Amendment to the Fourth Amended and Restated Credit Agreement and Consent (the “Sixth Amendment”) to its credit facility with Bank Lending Group. Under the Sixth Amendment, borrowings will bear interest at its option at the administrative agent’s reference rate plus an applicable margin or London Interbank Offering Rate (LIBOR) plus an applicable margin. The applicable margins for the Partnership’s interest rate and letter of credit fees vary quarterly based on the Partnership’s leverage ratio as defined by the credit facility (the “Leverage Ratio” being generally computed as total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows beginning February 27, 2009:

		Bank
		Reference
		Rate				LIBOR Rate				Letter of
Leverage Ratio		Advances(a)				Advances(b)				Credit Fees(c)				Commitment Fees(d)
Greater than or equal to 5.00 to 1.00			3.00	%			4.00	%			4.00	%			0.50	%
Greater than or equal to 4.25 to 1.00 and less than 5.00 to 1.00			2.50	%			3.50	%			3.50	%			0.50	%
Greater than or equal to 3.75 to 1.00 and less than 4.25 to 1.00			2.25	%			3.25	%			3.25	%			0.50	%
Less than 3.75 to 1.00			1.75	%			2.75	%			2.75	%			0.50	%

(a)

The applicable margins for the bank reference rate advances ranged from 0% to 0.25% under the bank credit facility prior to the Fifth and Sixth Amendments. The applicable margin for the bank reference rate advances was paid at the maximum rate of 2.00% under the Fifth Amendment from the November 7, 2008 until February 27, 2009.

(b)

The applicable margins for the LIBOR rate advances ranged from 1.00% to 1.75% under the bank credit facility prior to the Fifth and Sixth Amendments. The applicable margin for the bank reference rate advances was paid at the maximum rate of 3.00% under the Fifth Amendment from the November 7, 2008 until February 27, 2009.

(c)

The letter of credit fees ranged from 1.00% to 1.75% per annum plus a fronting fee of 0.125% per annum under the bank credit facility prior to the Fifth and Sixth Amendments. The letter of credit fees were paid at the maximum rate of 3.00% per annum in addition to the fronting fee under the Fifth Amendment from the November 7, 2008 until February 27, 2009.

(d)

The commitment fees ranged from 0.20% to 0.375% per annum on the unused amount of the credit facility under the bank credit facility prior to the Fifth and Sixth Amendments. The commitment fees were paid at the maximum rate of 0.50% per annum under the Fifth Amendment from the November 7, 2008 until February 27, 2009.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

     The Sixth Amendment also sets a floor for the LIBOR interest rate of 2.75% per annum , which means, effective as of February 27, 2009, borrowings under the bank credit facility accrue interest at the rate of 6.75% based on the LIBOR rate in effect on such date and the Partnership’s current leverage ratio. Based on the Partnership’s forecasted leverage ratios for 2009, it expects the applicable margins to be at the high end of these ranges for its interest rate and letter of credit fees.

     Pursuant to the Sixth Amendment, the Partnership must pay a leverage fee if it does not prepay debt and permanently reduce the banks’ commitments by the cumulative amounts of $100.0 million on September 30, 2009, $200.0 million on December 31, 2009, and $300.0 million on March 31, 2010. If the Partnership fails to meet any de-leveraging target, the Partnership must pay a leverage fee on such date, equal to the product of the aggregate commitments outstanding under its bank credit facility and the outstanding amount of senior secured note agreement on such date, and 1.0% on September 30, 2009, 1.0% on December 31, 2009, and 2.0% on March 31, 2010. This leverage fee will accrue on the applicable date, but not be payable until the Partnership refinances its bank credit facility.

     Under the Sixth Amendment, the maximum Leverage Ratio is as follows:

•		7.25 to 1.00 for the fiscal quarter ending March 31, 2009;
•		8.25 to 1.00 for the fiscal quarters ending June 30, 2009 and September 30, 2009;
•		8.50 to 1.00 for the fiscal quarter ending December 31, 2009;
•		8.00 to 1.00 for the fiscal quarter ending March 31, 2010;
•		6.65 to 1.00 for the fiscal quarter ending June 30, 2010;
•		5.25 to 1.00 for the fiscal quarter ending September 30, 2010;
•		5.00 to 1.00 for the fiscal quarter ending December 31, 2010;
•		4.50 to 1.00 for any fiscal quarters ending March 31, 2011 through March 31, 2012; and
•		4.25 to 1.00 for any fiscal quarters ending June 30, 2012 and thereafter..

     The minimum cash interest coverage ratio (as defined in the agreement, measured quarterly on a rolling four-quarter basis) is as follows under the Sixth Amendment:

•		1.75 to 1.00 for the fiscal quarters ending March 31, 2009;
•		1.50 to 1.00 for the fiscal quarter ending June 30, 2009;
•		1.30 to 1.00 for the fiscal quarter ending September 30, 2009;
•		1.15 to 1.00 for the fiscal quarter ending December 31, 2009;
•		1.25 to 1.00 for the fiscal quarter ending March 31, 2010;
•		1.50 to 1.00 for the fiscal quarter ending June 30, 2010;
•		1.75 to 1.00 for any fiscal quarter ending September 30, 2010 and December 31, 2010; and
•		2.50 to 1.00 for any fiscal quarter ending March 31, 2011 and thereafter.

     Under the Sixth Amendment, no quarterly distributions may be paid to partners unless the PIK notes have been repaid and the Leverage Ratio is less than 4.25 to 1.00. If the Leverage Ratio is between 4.00 to 1.00 and 4.25 to 1.00, the Partnership may make the minimum quarterly distribution of up to $0.25 per unit if the PIK notes have been repaid. If the Leverage Ratio is less than 4.00 to 1.00, the Partnership may make quarterly distributions to partners from available cash as provided by its partnership agreement if the PIK notes have been repaid. The PIK notes are due six months after the earlier of the refinancing or maturity of the bank credit facility. Based on its forecasted leverage ratios for 2009 and the Partnership’s near term ability to refinance its bank credit facility, the Partnership does not anticipate making quarterly distributions during 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results. The Partnership will not be able to make distributions to its unitholders in future periods if its leverage ratio does not improve.

     The Sixth Amendment also limits the Partnership’s annual capital expenditures (excluding maintenance capital expenditures) to $120.0 million in 2009 and $75.0 million in 2010 and each year thereafter (with unused amounts in any year being carried forward to the next year). It is unlikely that the Partnership will be able to make any acquisitions based on the terms of our credit facility and the current condition of the capital markets because it may only use a portion of the proceeds from the incurrence of unsecured debt and the issuance of equity to make such acquisitions.

     The Sixth Amendment also eliminated the accordion in our bank credit facility, which previously had permitted us to increase commitments thereunder by certain amounts if any bank was willing to undertake such commitment increase.

     The Sixth Amendment also revised the terms for mandatory repayment of outstanding indebtedness from asset sales and proceeds from incurrence of unsecured debt and equity issuances. Proceeds from debt issuances and equity issuances not required to prepay indebtedness are considered to be “Excess Proceeds” under the amended bank credit agreement. The Partnership may retain all Excess Proceeds. The following table sets forth the amended prepayment terms:

		% of Net Proceeds				% of Net Proceeds				% of Net Proceeds
		from Asset Sales				from Debt Issuances				from Equity Issuance
		Required for				Required for				Required for
Leverage Ratio*		Prepayment				Prepayment				Prepayment
Greater than or equal to 4.50			100	%			100	%		50	%
Greater or equal to 3.50 and Less Than 4.50			100	%			50	%		25	%
Less than 3.50			100	%			0	%		0	%

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

*

The Leverage Ratio is to be adjusted to give effect to proceeds from debt or equity issuance and the use of such proceeds for each proportional level of Leverage Ratio.

     The prepayments are to be applied pro rata based on total debt (including letter of credit obligations) outstanding under the bank credit agreement and the total debt outstanding under the note agreement described below. Any prepayments of advances on the bank credit facility from proceeds from asset sales, debt or equity issuances will permanently reduce the borrowing capacity or commitment under the facility in an amount equal to 100% of the amount of the prepayment. Any such commitment reduction will not reduce the banks' $300.0 million commitment to issue letters of credit.

     In addition, the bank credit facility contains various covenants that, among other restrictions, limit the Partnership’s ability to:

	•		incur indebtedness;
	•		grant or assume liens;
	•		make certain investments;
	•		sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
	•		change the nature of its business;
	•		enter into certain commodity contracts;
	•		make certain amendments to its or the operating partnership’s partnership agreement; and
	•		engage in transactions with affiliates.

     Each of the following will be an event of default under the bank credit facility:

	•		failure to pay any principal, interest, fees, expenses or other amounts when due;
	•		failure to observe any agreement, obligation, or covenant in the credit agreement, subject to cure periods for certain failures;
	•		certain judgments against us or any of its subsidiaries, in excess of certain allowances;
	•		certain ERISA events involving the Partnership or its subsidiaries;
	•		bankruptcy or other insolvency events;
	•		a change in control (as defined in the credit agreement); and
	•		the failure of any representation or warranty to be materially true and correct when made.

     If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under our bank credit facility will immediately become due and payable. If any other event of default exists under the bank credit facility, the lenders may accelerate the maturity of the obligations outstanding under the bank credit facility and exercise other rights and remedies.

      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 8 to the financial statements for a discussion of interest rate swaps.

     Senior Secured Notes. The Partnership entered into a master shelf agreement with an institutional lender in 2003 that was amended in subsequent years to increase availability under the agreement, pursuant to which it issued the following senior secured notes (dollars in thousands):

Month Issued

Amount

Interest Rate(1)

Maturity

Principal Payment Terms

June 2003(2)

$

30,000

9.45

%

7 years

Quarterly payments of

$1,765 from June

2006-June 2010

July 2003(2)

10,000

9.38

%

7 years

Quarterly payments of

$588 from July

2006-July 2010

June 2004

75,000

9.46

%

10 years

Annual payments of

$15,000 from July

2010-July 2014

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

November 2005			85,000				8.73	%		10 years				Annual payments of
														$17,000 from November
														2010-December 2014
March 2006			60,000				8.82	%		10 years				Annual payments of
														$12,000 from March
														2012-March 2016
July 2006			245,000				8.46	%		10 years				Annual payments of
														$49,000 from July
														2012-July 2016
Total Issued			505,000
Principal repaid			(25,294	)
Balance as of December 31, 2008		$	479,706

(1)

Interest rates have been adjusted to give effect to the 2% interest rate increase under the February 27, 2009 described below.

(2)

Principal repayments were $19.4 million and $5.9 million on the June 2003 and July 2003 notes, respectively.

     On November 7, 2008, the Partnership amended our senior secured note agreements governing its senior secured notes to, among other things, (i) modify the maximum permitted leverage ratio and lower the minimum interest coverage ratio it must maintain consistent with the ratios under the Fifth Amendment to the bank credit facility, (ii) permit it to sell certain assets and (iii) increase the interest rate it pays on the senior secured notes. The interest rate the Partnership paid on the senior secured notes increased by 1.25% for the fourth quarter of 2008 due to this amendment.

     The covenants and terms of default for the senior secured notes are substantially the same as the covenants and default terms under its bank credit facility, and therefore the agreement governing the senior secured notes also required amendment in 2009. On February 27, 2009, the Partnership amended its senior note agreement to (i) increase the maximum permitted leverage ratio and to lower the minimum interest coverage ratio it must maintain consistent with the ratios under the Amendment to the bank credit facility, (ii) revise the mandatory prepayment terms consistent with the terms under the Sixth Amendment to the bank credit facility, (iii) increase the interest rate it pays on the senior secured notes, and (iv) provide for the payment of a leverage fee consistent with the terms of the bank credit facility. Commencing February 27, 2009 the interest rate it pays in cash on all of the senior secured notes will increase by 2.25% per annum over the comparative interest rates under the senior note agreements prior to the November and February amendments. As a result of this rate increase, the weighted average interest rate on the outstanding balance on the senior secured notes is approximately 9.25% as of February 2009.

     Under the amended senior secured note agreement, the senior secured notes will accrue additional interest of 1.25% per annum of the senior secured note (the “PIK notes”) in the form of an increase in the principal amount unless the Partnership’s leverage ratio is less than 4.25 to 1.00 as of the end of any fiscal quarter. All PIK notes will be payable six months after the maturity of its bank credit facility, which is currently scheduled to mature in June 2011, or six months after refinancing of such indebtedness if prior to the maturity date.

     Per the terms of the amended senior note agreement, commencing on the date the Partnership refinances its bank credit facility, the interest rate payable in cash on its senior secured notes will increase by 1.25% per annum for any quarter if its leverage ratio as of the most recently ended fiscal quarter was greater than or equal to 4.25 to 1.00. In addition, commencing on June 30, 2012, the interest rate payable in cash on the Partnership’s senior secured notes will increase by 0.50% per annum for any quarter if its leverage as of the most recently ended fiscal quarter was greater than or equal to 4.00 to 1.00, but this incremental interest will not accrue if the Partnership is paying the incremental 1.25% per annum of interest described in the preceding sentence.

     These notes represent the Partnership’s senior secured obligations and will rank pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with the Partnership’s obligations under the credit facility, by first priority liens on all of its material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all its equity interests in substantially all of its subsidiaries. The senior secured notes are guaranteed by the Partnership’s material subsidiaries.

     The senior secured notes issued in 2003 are redeemable, at the Partnership’s option and subject to certain notice requirements, at a purchase price equal to 100% of the principal amount together with accrued interest, plus a make-whole amount determined in accordance with the senior secured note agreement. The senior secured notes issued 2004, 2005 and 2006 provide for a call premium of 103.5% of par beginning three years after issuance at rates declining from 103.5% to 100.0%. The notes are not callable prior to three years after issuance.

     If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of at least 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to the nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

     The senior secured note agreement relating to the notes contains substantially the same covenants and events of default as the Partnership’s bank credit facility.

     The Partnership was in compliance with all debt covenants at December 31, 2008 and expects to be in compliance with debt covenants for the next twelve months.

     Intercreditor and Collateral Agency Agreement. In connection with the execution of the senior secured note agreement, the lenders under the Partnership's bank credit facility and the purchasers of the senior secured notes have entered into an Intercreditor and Collateral Agency Agreement, which has been acknowledged and agreed to by the Partnership and its subsidiaries. This agreement appointed Bank of America, N.A. to act as collateral agent and authorized Bank of America to execute various security documents on behalf of the lenders under the Partnership's bank credit facility and the purchasers of the senior secured notes. This agreement specifies various rights and obligations of lenders under the bank credit facility, holders of senior secured notes and the other parties thereto in respect of the collateral securing the Partnership’s obligations under its bank credit facility and the senior secured note agreement. On February 27, 2009, the holders of the Partnership’s senior secured notes and a majority of the banks under its bank credit facility entered into an amendment to the Intercreditor and Collateral Agency Agreement, which provides that the PIK notes and certain treasury management obligations will be secured by the collateral for its bank credit facility and the senior secured notes, but only paid with proceeds of collateral after obligations under its bank credit facility and the senior secured notes are paid in full.

     Maturities. Maturities for the long-term debt as of December 31, 2008 are as follows (in thousands):

2009			9,412
2010			20,294
2011			816,000
2012			93,000
2013			93,000
Thereafter			232,000

(5) Other Long-Term Liabilities

     The Partnership entered into 9 and 10-year capital leases for certain compressor equipment. Assets under capital leases as of December 31, 2008 are summarized as follows (in thousands):

Compressor equipment		$	28,890
Less: Accumulated amortization			(1,523	)
Net assets under capital lease.		$	27,367

     The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of December 31, 2008 (in thousands):

Fiscal Year
2009 through 2013		$	16,150
Thereafter			16,691
Less: Interest			(5,184	)
Net minimum lease payments under capital lease			27,657
Less: Current portion of net minimum lease payments			(3,189	)
Long-term portion of net minimum lease payments		$	24,468

(6) Employee Incentive Plans

(a)

Long-Term Incentive Plan

     The Partnership’s managing general partner adopted a long-term incentive plan for its employees, directors, and affiliates who perform services for the Partnership. The plan currently permits the grant of awards covering an aggregate of 4,800,000 common unit options and restricted units. The plan is administered by the compensation committee of the managing general partner’s board of directors. The units issued upon exercise or vesting are newly issued units.

(b)

Restricted Units

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

     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 year ended December 31, 2008 is provided below:

Crosstex Energy, L.P. Restricted Units:

		Number of				Weighted Average
		Units				Grant-Date Fair
						Value
Non-vested, beginning of period			504,518			$	34.29
Granted			432,354				29.60
Vested*			(204,033	)			33.40
Forfeited			(34,273	)			26.69
Reduced estimated performance units			(154,499	)			31.66
Non-vested, end of period			544,067			$	31.90
Aggregate intrinsic value, end of period (in thousands)		$	2,378

*

Vested units include 51,214 units withheld for payroll taxes paid on behalf of employees.

     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 based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over a three-year period). 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 line in the table above. Target performance grants were previously included in the restricted units granted and were included in share-based compensation as it appeared probable that target thresholds would be achieved. However, during the last half of 2008, the Partnership’s assets were negatively impacted by hurricanes Gustav and Ike. During this same period the Partnership has also been negatively impacted by declines in natural gas and NGL prices coupled with the global economic decline and the recent tightening of capital markets. 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 year ended December 31, 2008. All performance-based awards greater than the minimum performance grant levels will be subject to reevaluation and adjustment until the restricted units vest. 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.

     A summary of the restricted units aggregate intrinsic value (market value at vesting date) and fair value of units vested (market value at date of grant) are provided below (in thousands):

Crosstex Energy, L.P. Restricted Units:		Year Ended December 31, 2008
Aggregate intrinsic value of units vested		$	5,907
Fair value of units vested		$	6,815

     As of December 31, 2008, there was $7.8 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(c)

Unit Options

     Unit options will have an exercise price that is not less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, unit options will become exercisable upon a change in control of the Partnership, its general partner or its general partner’s general partner.

     The fair value of each unit option award is estimated at the date of grant using the Black-Scholes-Merton model. This model is based on the assumptions summarized below. Expected volatilities are based on historical volatilities of the Partnership’s traded common units. The Partnership has used historical data to estimate share option exercise and employee departure behavior to estimate forfeiture rates . The expected life of unit options represents the period of time that unit options granted are expected to be outstanding. The risk-free interest rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of the grant. The Partnership used the simplified method to calculate the expected term.

     Unit options are generally awarded with an exercise price equal to the market price of the Partnership’s common units at the date of grant. The unit options granted in 2006, 2007 and 2008 generally vest based on 3 years of service (one-third after each year of service). The following weighted average assumptions were used for the Black-Scholes option-pricing model for grants in 2008:

Crosstex Energy, L.P. Unit Options Granted: —

Weighted average distribution yield			7.15	%
Weighted average expected volatility			30.0	%
Weighted average risk free interest rate			1.81	%
Weighted average expected life		6 years
Weighted average contractual life		10 years
Weighted average of fair value of unit options granted		$	3.48

     A summary of the unit option activity for the year ended December 31, 2008 is provided below:

						Weighted
		Number				Average
		of				Exercise
		Units					Price
Outstanding, beginning of period			1,107,309			$	29.65
Granted (b)			402,185				31.58
Exercised			(56,678	)			14.16
Forfeited			(90,208	)			31.29
Expired			(58,414	)			32.93
Outstanding, end of period			1,304,194			$	30.64
Options exercisable at end of period			540,782			$	29.12
Weighted average contractual term (years) end of period:
Options outstanding			7.4				—
Options exercisable			6.5				—
Aggregate intrinsic value end of period (in thousands):
Options outstanding		$	(a)				—
Options exercisable		$	(a)				—

	(a)		Exercise price on all outstanding options exceeds current market price.
	(b)		No options were granted with an exercise price less than market value at grant during 2008.

     A summary of the unit options intrinsic value (market value in excess of exercise price at date of exercise) exercised and fair value of units vested (value per Black-Scholes option pricing model at date of grant are provided below (in thousands):

Crosstex Energy, L.P. Unit Options:		Year Ended December 31, 2008
Intrinsic value of units options		$	746
exercised Fair value of units vested		$	279

     As of December 31, 2008, there was $1.6 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.5 years.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(d)

Crosstex Energy, Inc.’s Restricted Stock and Option Plan

     The Crosstex Energy, Inc. long-term incentive plan provides for the award of stock options and restricted stock (collectively, “Awards”) for up to 4,590,000 shares of Crosstex Energy, Inc.’s common stock. As of January 1, 2008, approximately 626,000 shares remained under the long-term incentive plan for future issuance to participants. A participant may not receive in any calendar year options relating to more than 100,000 shares of common stock. The maximum number of shares set forth above are subject to appropriate adjustment in the event of a recapitalization of the capital structure of Crosstex Energy, Inc. or reorganization of Crosstex Energy, Inc. Shares of common stock underlying Awards that are forfeited, terminated or expire unexercised become immediately available for additional Awards under the long-term incentive plan.

     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. CEI’s restricted stock granted in 2006, 2007 and 2008 generally cliff vest after three years of service. A summary of the restricted stock activity includes officers and employees of the Partnership and directors of CEI for the year ended December 31, 2008 is provided below:

						Weighted Average
		Number of				Grant-Date Fair
Crosstex Energy, Inc. Restricted Shares:		Shares				Value
Non-vested, beginning of period			860,275			$	21.16
Granted			361,796				32.62
Vested*			(401,004	)			18.41
Forfeited			(63,716	)			21.86
Reduced estimated performance shares			(153,038	)			32.10
Non-vested, end of period			604,313			$	27.62
Aggregate intrinsic value, end of period (in thousands)		$	2,357

     *Vested shares include 116,118 shares withheld for payroll taxes paid on behalf of employees.

     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 based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over a three-year period). 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 line in the table above. Target performance grants were previously included in the restricted units granted and were included in share-based compensation as it appeared probable that target thresholds would be achieved. However, during the last half of 2008, the Partnership’s assets were negatively impacted by hurricanes Gustav and Ike. During this same period the Partnership has also been negatively impacted by the declines in natural gas and NGL prices coupled with the global economic decline and 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 year ended December 31, 2008. All performance-based awards greater than the minimum performance grant levels will be subject to reevaluation and adjustment until the restricted shares vest. 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.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

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 years ended December 31, 2008 are provided below (in thousands):

Crosstex Energy, Inc. Restricted Shares:

		Years Ended December 31,
		2008
Aggregate intrinsic value of shares vested		$	13,493
Fair value of shares vested		$	7,382

     As of December 31, 2008, there was $7.2 million of unrecognized compensation costs related to CEI restricted shares for officers and employees. The cost is expected to be recognized over a weighted average period of 2.4 years.

CEI Stock Options

     No CEI stock options were granted to any officers or employees of the Partnership during 2008.

     A summary of the stock option activity includes officers and employees of the Partnership and directors of CEI for the years ended December 31, 2008 is provided below:

		Number				Weighted Average
		of Shares				Exercise Price
Outstanding, beginning of period			105,000			$	8.45

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

		Number				Weighted Average
		of Shares				Exercise Price
Granted			—				—
Cancelled			—				—
Exercised			(37,500	)			6.50
Forfeited			—				—
Outstanding, end of period			67,500			$	9.54
Options exercisable at end of period			22,500			$	11.05

     The following is a summary of the CEI stock options outstanding attributable to officers and employees of the Partnership as of December 31, 2008:

Outstanding stock options (15,000 exercisable) (post stock split)			30,000
Weighted average exercise price (post stock split)		$	13.33
Aggregate intrinsic value		$	—
Weighted average remaining contractual term		5.9 years

A summary of the share options intrinsic value (market value in excess of exercise price at date of exercise) exercised and fair value of units vested (value per Black-Scholes option pricing model at date of grant) during the years ended December 31, 2008 is provided below (in thousands):

Crosstex Energy, Inc. Stock Options: —

Intrinsic value of units options exercised		$	1,089
Fair value of units vested		$	38

     No stock options were granted, cancelled, exercised or forfeited by officers and employees of the Partnership during the years ended December 31, 2008.

     As of December 31, 2008, there was $15,449 of unrecognized compensation costs related to non-vested CEI stock options. The cost is expected to be recognized over a weighted average period of 0.8 years.

(7) Fair Value of Financial Instruments

     The estimated fair value of the Partnership’s financial instruments has been determined by the Partnership using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided below are not necessarily indicative of the amount the Partnership could realize upon the sale or refinancing of such financial instruments as of December 31, 2008 (in thousands):

		Carrying				Fair
		Value				Value
Cash and cash equivalents		$	1,636			$	1,636
Trade accounts receivable and accrued revenues			341,853				341,853
Fair value of derivative assets			31,794				31,794
Note receivable			375				375
Accounts payable, drafts payable and accrued gas purchases			315,622				315,622
Current portion of long-term debt			9,412				9,412
Long-term debt			1,254,294				1,148,939
Fair value of derivative liabilities			51,281				51,281

     The carrying amounts of the Partnership’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these assets and liabilities. The carrying value for the note receivable approximates the fair value because this note earns interest based on the current prime rate.

     The Partnership’s long-term debt was comprised of borrowings under a revolving credit facility totaling $784.0 million as of December 31, 2008 that accrues interest under a floating interest rate structure. Accordingly, the carrying value of such indebtedness approximates fair value for the amounts outstanding under the credit facility. As of December 31, 2008, the Partnership also had

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

borrowings totaling $479.7 million under senior secured notes with a weighted average interest rate of 7.25%. The fair value of these borrowings as of December 31, 2008 was adjusted to reflect current market interest rate for such borrowings as of December 31, 2008.

     The fair value of derivative contracts included in assets or liabilities for risk management activities represents the amount at which the instruments could be exchanged in a current arms-length transaction.

(8) Derivatives

Interest Rate Swaps

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

     The Partnership has entered into eight interest rate swaps as of September 2008 as shown below:

																		Notional Amounts
Trade Date		Term				From				To				Rate				(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

     *Amended swap is a combination of two swaps that each had a notional amount of $50.0 million 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 new 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 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 year ended December 31, 2008 is $6.4 million.

     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.

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

     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

Notional Amounts

Date

New Trade Date

From

To

(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

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

		December 31, 2008
Fair value of derivative assets — current		$	149
Fair value of derivative assets — long-term			—
Fair value of derivative liabilities — current			(17,217	)
Fair value of derivative liabilities — long-term			(18,391	)
Net fair value of interest rate swaps		$	(35,459	)

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.

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

		December 31, 2008
Fair value of derivative assets — current		$	27,017
Fair value of derivative assets — long term			4,628
Fair value of derivative liabilities — current			(11,289	)
Fair value of derivative liabilities — long term			(4,384	)
Net fair value of commodity swaps		$	15,972

     Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at December 31, 2008 (all gas volumes are expressed in MMBtu’s and liquids are expressed in gallons). The remaining terms 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 derivative contracts include BP Corporation, Total Gas & Power, Fortis, UBS Energy, Morgan Stanley, J. Aron & Co., a subsidiary of Goldman Sachs and Sempra Energy. Changes in the fair value of the

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

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.

		December 31, 2008
Transaction Type		Volume				Fair Value
		(In thousands)
Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)			(600	)		$	1,136
Liquids swaps (short contracts) (gallons)			(16,026	)			12,578
Total swaps designated as cash flow hedges						$	13,714
Mark to Market Derivatives:* Swing swaps (long contracts)			2,155			$	10
Physical offsets to swing swap transactions (short contracts)			(2,155	)			—
Swing swaps (short contracts)			(397	)			(3	)
Physical offsets to swing swap transactions (long contracts)			397				—
Basis swaps (long contracts)			82,681				7,464
Physical offsets to basis swap transactions (short contracts)			(1,550	)			9,072
Basis swaps (short contracts)			(78,025	)			(6,175	)
Physical offsets to basis swap transactions (long contracts)			1,771				(9,067	)
Third-party on-system financial swaps (long contracts)			2,300				(8,065	)
Physical offsets to third-party on-system transactions (short contracts)			(2,283	)			8,157
Third-party on-system financial swaps (short contracts)			(172	)			2
Physical offsets to third-party on-system transactions (long contracts)			155				89
Storage swap transactions (long contracts)			158				(23	)
Storage swap transactions (short contracts)			(353	)			797
Total mark to market derivatives						$	2,258

     *All are gas contracts, volume in MMBtu’s

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

Impact of Cash Flow Hedges

Natural Gas

     As of December 31, 2008 an unrealized derivative fair value net gain of $1.1 million related to cash flow hedges of gas price risk was recorded in accumulated other comprehensive income (loss). Of this net amount, a $1.1 million gain is expected to be reclassified into earnings through December 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 actively quoted prices. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

		Maturity Periods
		Less Than One Year				One to Two Years				More Than Two Years				Total Fair Value
December 31, 2008		$	2,014			$	181			$	63			$	2,258

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

(9) 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.

     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		$	(35,459	)			—			$	(35,459	)			—
Commodity swaps			15,972				—				15,972				—
Total		$	(19,487	)			—			$	(19,487	)			—

(10) Commitments and Contingencies

     (a) Leases — Lessee

     The Partnership has operating leases for office space, office and field equipment and the Eunice plant. The Eunice plant operating lease acquired with the south Louisiana processing assets provides for annual lease payments of $12.2 million with a lease term extending to November 2012. At the end of the lease term we have the option to purchase the plant for $66.3 million or to renew the lease for up to an additional 9.5 years at 50% of the lease payments under the current lease.

     The following table summarizes our remaining non-cancelable future payments under operating leases with initial or remaining non-cancelable lease terms in excess of one year (in millions):

2009		$	28.4
2010			19.0
2011			17.9
2012			16.4
2013			3.1
Thereafter			3.7
		$	88.5

     (b) Leases — Lessor

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

     During 2008, the Partnership leased approximately 162 of its treating plants, most of which the Partnership operates, and 33 of its dew point control plants to customers under operating leases. The initial terms on these leases are generally 12 months, at which time the leases revert to 30-day cancelable leases. As of December 31, 2008, the Partnership only had 31 treating plants under 36 operating leases with remaining non-cancelable lease terms in excess of one year. The future minimum lease rentals are $16.3 million and $5.4 million for the years ended December 31, 2009 and 2010, respectively. These leased treating plants have a cost of $25.4 million and accumulated depreciation of $4.9 million as of December 31, 2008.

     (c) Employment Agreements

     Certain members of management of the Partnership are parties to employment contacts 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.

     (d) Environmental Issues

     The Partnership acquired the South Louisiana Processing Assets from the El Paso Corporation in November 2005. One of the acquired locations, the Cow Island Gas Processing Facility, has an active remediation project for benzene contaminated groundwater. The cause of contamination was attributed to a leaking natural gas condensate storage tank. The site investigation and active remediation being conducted at this location is under the oversight of the Louisiana Department of Environmental Quality (LDEQ) and is being conducted under the Risk-Evaluation and Corrective Action Plan Program (RECAP) rules. In addition, the Partnership is working with both the LDEQ and the Louisiana State University, Louisiana Water Resources Research Institute, on the development and implementation of a new remediation technology that is expected to significantly reduce the cost of and timing for remediation projects. As of December 31, 2007, we had incurred approximately $0.5 million in remediation costs. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to our ownership, projected costs were accrued as part of the purchase price.

     The Partnership acquired LIG Pipeline Company and its subsidiaries on April 1, 2004. Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third-party company that specializes in remediation work. The Partnership does not expect to incur any material liability with these sites; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it has discovered to the LDEQ and is working with the department to correct these deficiencies and to address modifications to facilities to bring them into compliance. The Partnership does not expect to incur any material environmental liability associated with these issues.

     The Partnership acquired assets from Duke Energy Field Services, or DEFS, in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of the Conroe site. Moreover, a third-party company has assumed the remediation costs associated with the Conroe site. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe site; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.

     (e) 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 Processing”), the Partnership’s wholly-owned subsidiary, 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. On April 15, 2008, the parties mediated the matter unsuccessfully. On December 4, 2008, Denbury initiated formal arbitration proceedings against Crosstex Processing, Crosstex Energy Services, L.P., Crosstex North Texas Gathering, L.P., and Crosstex Gulf Coast Marketing, Ltd., seeking $11.4 million and additional unspecified damages. On December 23, 2008, Crosstex Processing filed an answer denying Denbury’s allegations and a counterclaim seeking a

CROSSTEX ENERGY GP, L.P.

Notes to Consolidated Balance Sheet — (Continued)

declaratory judgment that its processing plant is uneconomic under the Processing Contract. Crosstex Energy, Crosstex Marketing, and Crosstex Gathering also filed an answer denying Denbury’s allegations and asserting that they are improper parties as Denbury’s claim is for breach of the Processing Contract and none of these entities is a party to that agreement. Crosstex Gathering also filed a counterclaim seeking approximately $40.0 million in damages for the value of the NGLs it is entitled to under its Gas Gathering Agreement with Denbury. Once the three-person arbitration panel has been named and cleared conflicts, the arbitration panel will hold a preliminary conference with the parties to set a date for the final hearing and other case deadlines and to establish discovery limits. Although it is not possible to predict with certainty the ultimate outcome of this matter, the Partnership does not believe this will have a material adverse effect on its consolidated results of operations or financial position.

     The Partnership (or its subsidiaries) is defending eleven 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. At this time, five cases are set for trial in 2009. The remaining cases have not yet been set for trial. Discovery is underway. 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, SemStream, 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, SemStream, L.P. owed the Partnership approximately $6.2 million, including approximately $3.9 million for June 2008 sales and approximately $2.2 million for July 2008 sales. The Partnership believes the July sales of $2.2 million will receive “administrative claim” status in the bankruptcy proceeding. The debtor’s schedules acknowledge its obligation to Crosstex for an administrative claim in the amount of $2.2 but the allowance of the administrative claim status is still subject to approval of the bankruptcy court in accordance with the administrative claim allowance procedures order in the case. The Partnership evaluated these receivables for collectibility and provided a valuation allowance of $3.1 million during the year ended December 31, 2008.

(11) 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 pipelines and processing plants located in Louisiana, the Mississippi System, the Arkoma system 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 through fixed monthly payments.

     The accounting policies of the operating segments are the same as those described in note 2 of the Notes to Consolidated Financial Statements. Corporate assets consist principally of property and equipment, including software, for general corporate support, working capital and debt financing costs.

     The identifiable assets by segment as of December 31, 2008 are as follows (in thousands):

Midstream		$	2,303,679
Treating			200,114
Corporate			29,473
Total		$	2,533,266

(12) Condensed Consolidating Information

     The following table presents the condensed consolidating balance sheet data for the General Partner and CELP as of December 31, 2008 (in thousands):