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, 2007. 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, 2007, in conformity with U.S. generally accepted accounting principles.

      

      

/s/ KPMG LLP

Dallas, Texas
April 8, 2008

ASSETS
Current assets:
Cash and cash equivalents		$	143
Accounts receivable:
Trade, net of allowance for bad debts of $985			46,441
Accrued revenues			443,448
Imbalances			3,865
Affiliated companies			38
Note receivable			1,026
Other			2,531
Fair value of derivative assets			8,589
Natural gas and natural gas liquids, prepaid expenses, and other			16,062
Total current assets			522,143
Property and equipment:
Transmission assets			468,692
Gathering systems			460,420
Gas plants			565,415
Other property and equipment			64,073
Construction in process			79,889
Total property and equipment			1,638,489
Accumulated depreciation			(213,327	)
Total property and equipment, net			1,425,162
Fair value of derivative assets			1,337
Intangible assets, net of accumulated amortization of $60,118			610,076
Goodwill			24,540
Other assets, net			9,617
Total assets		$	2,592,875
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Drafts payable		$	28,931
Accounts payable			13,727
Accrued gas purchases			427,293
Accrued imbalances payable			9,447
Accrued construction in process costs			12,732
Fair value of derivative liabilities			21,066
Current portion of long-term debt			9,412
Other current liabilities			46,422
Total current liabilities			569,030
Long-term debt			1,213,706
Other long-term liabilities			3,553
Deferred tax liability			8,518
Minority interest			764,090
Fair value of derivative liabilities			9,426
Commitments and contingencies			—
Partners’ equity			24,552
Total liabilities and partners’ equity		$	2,592,875

See accompanying notes to consolidated balance sheet.

(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. 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 natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas to a variety of markets. In addition, CELP purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.

          (b) Partnership Ownership

          As of December 31, 2007, CEI also owns 4,668,000 subordinated units, 6,414,830 senior subordinated series C units and 5,332,000 common units in CELP through its wholly-owned subsidiaries. As of December 31, 2007, CEI owned 36.3% of the limited partner interests in CELP and officers and directors owned 1.20% of the limited partnership interests. The remaining units are held by the public. As of December 31, 2007, Crosstex Energy Services (CES) management and directors owned 7.87% of CEI.

          In February 2008, 4,668,000 of CEI’s subordinated units and 6,414,830 senior subordinated series C units converted to common units so that the current ownership of common units is 16,414,830.

          (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 12.4% interest in a carbon dioxide processing plant acquired by CELP in June 2004 and 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) Adoption of Emerging Issues Task Force Issue No. 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights”.

          Effective January 1, 2006, the General Partner adopted Emerging Issues Task Force Issue 04-5, “Investor’s Accounting for an Investment in a Limited Partnership When the Investor is the Sole General Partner and the Limited Partners Have Certain Rights” (EITF 04-5). The General Partner is required to consolidate CELP in accordance with EITF 04-5 because it has substantive participating rights as the general partner of CELP.

     (b) 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.

     (c) Cash and Cash Equivalents

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

     (d) Natural Gas and Natural Gas Liquids Inventory

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

     (e) Property, Plant, and Equipment

          Property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, industrial supply pipelines, natural gas liquids pipelines, natural gas processing plants, NGLs fractionation plants, an undivided 12.4% interest in a carbon dioxide processing plant 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. 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, gas processing and carbon dioxide 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.

     (f) Goodwill and Intangibles

          The Partnership has approximately $24.5 million of goodwill at December 31, 2007. During the formation of the Partnership in May 2001, $5.4 million of goodwill was created and later amortized by $0.5 million. Goodwill of approximately $1.7 million in 2005 and $17.9 million in 2006 resulted from three acquisitions in our Treating segment. The goodwill related to the formation of the Partnership has been allocated to the Midstream segment. Goodwill is 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.

     (g) Other Assets

          Unamortized debt issuance costs totaling $9.6 million at December 31, 2007 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 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.

     (h) 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. The Partnership had imbalance payables of $9.4 million at December 31, 2007 which approximates the fair value of these imbalances. The Partnership had imbalance receivables of $3.9 million at December 31, 2007 which are carried at the lower of cost or market value.

     (i) 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, 2007 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.

     (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.

     (k) Energy Trading Activities

          The Partnership conducts “off-system” gas marketing operations as a service to producers on systems that the Partnership does not own. The Partnership refers to these activities as its energy trading activities. In some cases, the Partnership earns an agency fee from the producer for arranging the marketing of the producer’s natural gas. In other cases, the Partnership purchases the natural gas from the producer and enters into a sales contract with another party to sell the natural gas.

          The Partnership manages its price risk related to future physical purchase or sale commitments for its energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance the Partnership’s future commitments and significantly reduce its risk to the movement in natural gas prices. However, the Partnership is

subject to counter-party risk for both the physical and financial contracts. The Partnership’s energy trading contracts qualify as derivatives, and accordingly, the Partnership continues to use mark-to-market accounting for both physical and financial contracts of its energy trading activities.

     (l) 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.

     (m) Income Taxes

          The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners including CEI as the indirect owner of the General Partner. The net tax basis in the Partnership’s assets and liabilities is less than the reported amounts on the financial statements by approximately $337.8 million as of December 31, 2007. Effective January 1, 2007, the Partnership will be subject to the gross margin tax enacted by the state of Texas on May 1, 2006. The new tax law had no significant impact on the Partnership’s deferred tax liability.

          The Partnership owns four entities that are treated as taxable corporations for income tax purposes. The entity structure was formed when the Partnership acquired the stock of these entities in 2004 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. 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 these 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 has been 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 as of December 31, 2007 (in thousands):

Deferred income tax assets:
Net operating loss carryforward — current		$	4
Net operating loss carryforward — long-term			61
Alternative minimum tax credit carryover — long-term			99
		$	164
Deferred income tax liabilities:
Property, plant, equipment, and intangible assets—current		$	(501	)
Property, plant, equipment and intangible assets—long-term			(8,678	)
		$	(9,179	)
Net deferred tax liability		$	(9,015	)

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

     (n) 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.

     (o) Cash Distributions

          In accordance with the partnership agreement, 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. See Note (5) for a description of the bank credit facility covenants.

          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 $24.8 million were earned by the General Partner for the year ended December 31, 2007. 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, 2007.

          CELP increased its fourth quarter 2007 distribution on its common and subordinated units to $0.61 per unit, which distribution was paid on February 15, 2008.

     (p) 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.

     (q) 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 applied the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), for periods prior to January 1, 2006.

          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. The Partnership adjusted compensation cost for actual forfeitures as they occurred under APB No. 25 for periods prior to January 1, 2006. 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.

     (r) Recent Accounting Pronouncements

          In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which the Partnership adopted effective January 1, 2007. FIN 48 addressed the determination of how tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The adoption of FIN 48 had no material impact to our financial statements. At December 31, 2007, we have no material assets, liabilities or accrued interest and penalties associated with uncertain tax positions. 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, 2007, tax years 2000 through 2007 remain subject to examination by the Internal Revenue Service and applicable states. We do not expect any material change in the balance of our unrecognized tax benefits over the next twelve months.

          In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. While SFAS 157 does not add any new fair value measurements, it is intended to increase consistency and comparability of such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

          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 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.

(3) Investment in Joint Venture and Note Receivable

          The Partnership owns a 50% interest in CDC and consolidates its investment in CDC pursuant to FIN No. 46R. The Partnership manages the business affairs of CDC. The other 50% joint venture partner (the CDC partner) is an unrelated third party who owns and operates a natural gas field located in Denton County.

          In connection with the formation of CDC, the Partnership agreed to loan the CDC partner up to $1.5 million for its initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC partner’s 50% share of distributable cash flow to repay the loan. Any balance remaining on the note is due in August 2008. The balance remaining on the note of $1.0 million is included in current notes receivable as of December 31, 2007.

(4) Long-Term Debt

          As of December 31, 2007, 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, 2007 was 6.71%		$	734,000
Senior secured notes, weighted average interest rate at December 31, 2007 of 6.75%			489,118
			1,223,118
Less current portion			(9,412	)
Debt classified as long-term		$	1,213,706

          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, 2007, $861.3 million was outstanding under the bank credit facility, including $127.3 million of letters of credit, leaving approximately $323.7 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 certain of its subsidiaries, and rank pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by certain of the Partnership’s 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.

          Under the amended credit agreement, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on the Partnership’s leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees ranging from 0.20% to 0.375% on the unused amount of the credit facilities.

          The credit agreement prohibits the Partnership from declaring distributions to unit-holders if any event of default, as defined in the credit agreement, exists or would result from the declaration of distributions. 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;
	•		make distributions;
	•		change the nature of its business;
	•		enter into certain commodity contracts;
	•		make certain amendments to the Partnership’s or its operating partnership’s partnership agreement; and
	•		engage in transactions with affiliates.

          In April 2007, the Partnership amended its bank credit facility, effective as of March 28, 2007, to increase the maximum permitted leverage ratio for the fiscal quarter ending September 30, 2007 and each fiscal quarter thereafter. The maximum leverage ratio (total funded debt to consolidated earnings before interest, taxes, depreciation and amortization) is as follows (provided, however, that during an acquisition period as defined in the bank credit facility, the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable ratio set forth below):

•

5.25 to 1.00 for fiscal quarters through December 31, 2007;

	•		5.00 to 1.00 for any fiscal quarter ending March 31, 2008 through September 2008;
	•		4.75 to 1.00 for fiscal quarters ending December 31, 2008 and March 31, 2009; and
	•		4.50 to 1.00 for any fiscal quarter ending thereafter.

          Additionally, the bank credit facility now provides that (i) if the Partnership or its subsidiaries incur unsecured note indebtedness, the leverage ratio will shift to a two-tiered structure and (ii) during periods where the Partnership has outstanding unsecured note indebtedness, the Partnership’s leverage ratio cannot exceed 5.50 to 1.00 and the Partnership’s senior leverage ratio cannot exceed 4.50 to 1.00. The other material terms and conditions of the credit facility remained unchanged.

          The bank credit facility contains the following covenants requiring the Partnership to maintain:

•

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

          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 the Partnership or any of its subsidiaries, in excess of certain allowances;
	•		certain ERISA events involving the Partnership or the Partnership’s subsidiaries;
	•		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.

          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

Maturity

Principal Payment Terms

June 2003

$

30,000

6.95

%

7 years

Quarterly payments of

$1,765 from June

2006-June 2010

July 2003

10,000

6.88

%

7 years

Quarterly payments of

$588 from July

2006-July 2010

June 2004

75,000

6.96

%

10 years

Annual payments of

$15,000 from July

2010-July 2014

November 2005

85,000

6.23

%

10 years

Annual payments of

$17,000 from November

2010-December 2014

March 2006

60,000

6.32

%

10 years

Annual payments of

$12,000 from March

2012-March 2016

July 2006

245,000

6.96

%

10 years

Annual payments of

$49,000 from July

2012-July 2016

Total Issued

505,000

Principal repaid

(15,882

)

Balance as of December 31, 2007

$

489,118

          In April 2007, the Partnership amended the senior note agreement, effective as of March 30, 2007, to (i) provide that if the Partnership’s leverage ratio at the end of any fiscal quarter exceeds certain limitations, the Partnership will pay the holders of the senior secured notes an excess leverage fee based on the daily average outstanding principal balance of the senior secured notes during such fiscal quarter multiplied by certain percentages set forth in the senior note agreement; (ii) increase the rate of interest on each senior secured note by 0.25% if, at any given time during an acquisition period (as defined in the senior note agreement), the leverage ratio exceeds 5.25 to 1.00; (iii) cause the leverage ratio to shift to a two-tiered structure if the Partnership or its subsidiaries incur unsecured note indebtedness; and (iv) limit the Partnership’s leverage ratio to 5.25 to 1.00 and the Partnership’s senior leverage ratio to 4.25 to 1.00 during periods where the Partnership has outstanding unsecured note indebtedness. The other material items and conditions of the senior note agreement remained unchanged.

          These notes represent senior secured obligations of the Partnership and will rank at least pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with obligations of the Partnership 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 certain of its subsidiaries. The senior secured notes are guaranteed by the Partnership’s subsidiaries.

          The $40.0 million of 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 master shelf 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. During 2008 the notes may also incur an additional fee each quarter of 0.15% per annum on the outstanding borrowings if the Partnership’s leverage ratio, as defined in the agreement, exceeds certain levels during such quarterly period.

          The master shelf agreement relating to the notes contains substantially the same covenants and events of default as the bank credit facility.

          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.

          The Partnership was in compliance with all debt covenants at December 31, 2007 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 master shelf agreement, the lenders under the 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 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 the bank credit facility and the master shelf agreement.

          Maturities. Maturities for the long-term debt as of December 31, 2007 are as follows (in thousands):

2008		$	9,412
2009			9,412
2010			20,294
2011			766,000
2012			93,000
Thereafter			325,000

(5) Other Long-Term Liabilities

          In November 2007, the Partnership entered into a 10-year capital lease for certain compressor equipment. Assets under capital leases as of December 31, 2007 are summarized as follows (in thousands):

Compressor equipment		$	4,011
Less: Accumulated amortization			(29	)
Net assets under capital lease		$	3,982

          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, 2007 (in thousands):

Fiscal Year
2008 through 2012 ($445 annually)		$	2,225
Thereafter			2,743
Less: Interest			(980	)
Net minimum lease payments under capital lease			3,988
Less: Current portion of net minimum lease payments			(435	)
Long-term portion of net minimum lease payments		$	3,553

(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

          A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. In addition, the restricted units will become exercisable upon a change of control of the Partnership, its general partner or its general partner’s general partner.

          The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive and the Partnership will receive no remuneration for the units. The restricted units include a tandem award that entitles the participant to receive cash payments equal to the cash distributions made by the Partnership with respect to its outstanding common units until the restriction period is terminated or the restricted units are forfeited. The restricted units granted in 2005, 2006 and 2007 generally cliff vest after three years of service.

          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, 2007 is provided below:

Crosstex Energy, L.P. Restricted Units:

						Weighted
						Average
		Number of				Grant-Date
		Units				Fair Value
Non-vested, beginning of period			336,504			$	32.01
Granted			224,262				35.26
Vested			(38,052	)			23.33
Forfeited			(18,196	)			26.99
Non-vested, end of period			504,518			$	34.29
Aggregate intrinsic value, end of period (in thousands)		$	15,650

          In July 2007, the Partnership’s executive officers were granted restricted units based on the accomplishment of certain performance targets. The target number of restricted units for all executives of 47,742 will be increased (up to a maximum of 200% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2007 through January 2010) compared to the Partnership’s target average growth rate of 10.5%. The restricted unit activity for the year ended December 31, 2007 reflects 47,742 performance-based restricted unit grants for executive officers based on current performance models. 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. All performance-based awards greater than the minimum performance grants will be subject to reevaluation and adjustment until the restricted units vest in January 2010.

          The aggregate intrinsic value of vested units during the year ended December 31, 2007 was $1.3 million. As of December 31, 2007, there was $6.8 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.3 years.

     (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. 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 contractual term of the unit option is based on the U.S. Treasury yield curve in effect at the time of the grant.

          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 2005, 2006 and 2007 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 2007:

Crosstex Energy, L.P. Unit Options Granted:

Weighted average distribution yield			5.75	%
Weighted average expected volatility			32.0	%
Weighted average risk free interest rate			4.39	%
Weighted average expected life		6 years
Weighted average contractual life		10 years
Weighted average of fair value of unit options granted		$	6.73

          A summary of the unit option activity for the year ended December 31, 2007 is provided below:

						Weighted
						Average
		Number of				Exercise
		Units				Price
Outstanding, beginning of period			926,156			$	25.70
Granted			347,599				37.29
Exercised			(90,032	)			18.20
Forfeited			(67,688	)			29.84
Expired			(8,726	)			31.60
Outstanding, end of period			1,107,309			$	29.65
Options exercisable at end of period			281,973			$	28.05
Weighted average contractual term (years) end of period:
Options outstanding			7.6				—
Options exercisable			7.1				—
Aggregate intrinsic value end of period (in thousands):
Options outstanding		$	4,681				—
Options exercisable		$	1,322				—

          The total intrinsic value of unit options exercised during the year ended December 31, 2007 was $1.7 million. As of December 31, 2007, there was $2.4 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.6 years.

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

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 924,533 shares remained under the long-term incentive plan for future issuance to participants.

          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 2005, 2006 and 2007 generally cliff vest after three years of service. A summary of the restricted stock activity for the year ended December 31, 2007 is provided below:

Crosstex Energy, Inc. Restricted Shares:

						Weighted
						Average
		Number of				Grant-Date
		Shares (a)				Fair Value
Non-vested, beginning of period			751,749			$	17.03
Granted			244,578				29.58
Vested			(90,156	)			14.14
Forfeited			(45,896	)			14.32
Non-vested, end of period			860,275			$	21.16
Aggregate intrinsic value, end of period (in thousands)		$	32,037

          In July 2007, the Partnership’s executive officers were granted restricted units based on the accomplishment of certain performance targets. The target number of restricted units for all executives of 55,131 will be increased (up to a maximum of 200% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2007 through January 2010) compared to the Partnership’s target average growth rate of 10.5%. The restricted unit activity for the period ended December 31, 2007 reflects 55,131 performance-based restricted unit grants for executive officers based on current performance models. 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 probably of achieving the performance criteria. All performance-based awards greater than the minimum performance grants will be subject to reevaluation and adjustment until the restricted units vest in January 2010.

          No CEI stock options were granted to any officers or employees of the Partnership during 2007.

     The following is a summary of the CEI stock options outstanding attributable to officers and employees of the Partnership as of December 31, 2007:

Outstanding stock options (non exercisable) (post stock split)			30,000
Weighted average exercise price (post stock split)		$	13.33
Aggregate intrinsic value		$	717,200
Weighted average remaining contractual term		6.9 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, 2007 (in thousands):

		Carrying				Fair
		Value				Value
Cash and cash equivalents		$	143			$	143
Trade accounts receivable and accrued revenues			489,889				489,889
Fair value of derivative assets			9,926				9,926
Note receivable			1,026				1,026
Accounts payable, drafts payable and accrued gas purchases			469,951				469,951
Current portion of long-term debt			9,412				9,412
Long-term debt			1,213,706				1,225,087
Fair value of derivative liabilities			30,492				30,492

          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 $734.0 million as of December 31, 2007 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, 2007, the Partnership also had borrowings totaling $489.1 million under senior secured notes with a weighted average interest rate of 6.75%. The fair value of these borrowings as of December 31, 2007 was adjusted to reflect to current market interest rate for such borrowings as of December 31, 2007.

          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 December 31, 2007 as shown below:

												Notional Amounts
Trade Date		Term		From		To		Rate				(in thousands):
November 14, 2006		3 years		November 28, 2006		November 30, 2009			4.950	%		$	50,000
March 13, 2007		3 years		March 30, 2007		March 31, 2010			4.875	%		$	50,000
July 30, 2007		3 years		August 30, 2007		August 30, 2010			5.070	%		$	100,000
August 6, 2007		3 years		August 30, 2007		August 30, 2010			4.970	%		$	50,000
August 9, 2007		2 years		November 30, 2007		November 30, 2009			4.950	%		$	50,000
August 16, 2007		3 years		October 31, 2007		October 31, 2010			4.775	%		$	50,000
September 5, 2007		3 years		September 28, 2007		September 30, 2010			4.700	%		$	50,000
September 11, 2007		3 years		October 31, 2007		October 31, 2010			4.540	%		$	50,000
												$	450,000

          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. The Partnership has 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 are recorded in accumulated other comprehensive income until the related interest rate expense is recognized in earnings.

          There is no ineffectiveness related to the interest rate swaps that qualify for hedge accounting.

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

		December 31, 2007
Fair value of derivative assets — current		$	68
Fair value of derivative assets — long-term			—
Fair value of derivative liabilities — current			(3,266	)
Fair value of derivative liabilities — long-term			(8,057	)
Net fair value of derivatives		$	(11,255	)

          At December 31, 2007 an unrealized loss of $10.2 million was recorded in accumulated other comprehensive income related to the interest rate swaps. Due to the decline in interest rates in January 2008, the Partnership revised the interest rate swaps to take advantage of the rate decline. The interest rate swaps were de-designated at that time and the Partnership will recognize the amounts in accumulated other comprehensive income as the swaps mature. Subsequent changes in fair value of the swaps will be recorded in current earnings.

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 frac 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,
		2007
Fair value of derivative assets — current		$	8,521
Fair value of derivative assets — long term			1,337
Fair value of derivative liabilities — current			(17,800	)
Fair value of derivative liabilities — long term			(1,369	)
Net fair value of derivatives		$	(9,311	)

          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, 2007 (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. 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 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, 2007
Transaction Type		Volume				Fair Value
		(In thousands)
Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)			(2,574	)		$	1,703
Liquids swaps (long contracts) (gallons)			2,452				1,352
Liquids swaps (short contracts) (gallons)			(33,396	)			(14,377	)
Total swaps designated as cash flow hedges						$	(11,322	)
Mark to Market Derivatives:*
Swing swaps (long contracts)			908			$	(8	)
Physical offsets to swing swap transactions (short contracts)			(908	)			—
Swing swaps (short contracts)			(2,285	)			3
Physical offsets to swing swap transactions (long contracts)			2,285				—
Basis swaps (long contracts)			36,700				1,449
Physical offsets to basis swap transactions (short contracts)			(3,570	)			26,283
Basis swaps (short contracts)			(31,825	)			(1,191	)
Physical offsets to basis swap transactions (long contracts)			5,555				(25,117	)
Third-party on-system financial swaps (long contracts)			4,551				(958	)
Physical offsets to third-party on-system transactions (short contracts)			(4,551	)			1,299
Third-party on-system financial swaps (short contracts)			(114	)			81
Physical offsets to third-party on-system transactions (long contracts)			114				(74	)
Third-party off-system financial swaps (short contracts)			(915	)			259
Physical offsets to third-party off-system transactions (long contracts)			915				(195	)
Storage swap transactions (long contracts)			150				(85	)
Storage swap transactions (short contracts)			(413	)			265
Total mark to market derivatives						$	2,011

*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.

Derivatives Other Than Cash Flow Hedges

          Assets and liabilities related to third party derivative contracts, puts, 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, 2007		$	1,570			$	344			$	97			$	2,011

(9) Commitments and Contingencies

     (a) Leases — Lessee

          We have operating leases for office space, office and field equipment and the Eunice plant. The Eunice plant operating lease acquired in the El Paso acquisition 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):

2008		$	24.7
2009			21.4
2010			18.4
2011			17.3
2012			16.3
Thereafter			6.8
		$	104.9

          (b) Leases — Lessor

          During 2007, the Partnership leased approximately159 of its treating plants 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, 2007, the Partnership only had 20 treating plants under 24 operating leases with remaining non-cancelable lease terms in excess of one year. The future minimum lease rentals are $8.3 million and $5.5 million for the years ended December 31, 2008 and 2009, respectively. These leased treating plants have a cost of $21.8 million and accumulated depreciation of $4.7 million as of December 31, 2007.

          (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 a known 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 guidance of the Louisiana Department of Environmental Quality (LDEQ) based on 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 will drastically reduce the remediation time as well as the costs associated with such remediation projects. As of December 31, 2007, we had incurred approximately $0.5 million in such remediation costs, of which $0.4 million had already been paid. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to our ownership, these 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. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it has discovered to the Louisiana Department of Environmental Quality and is working with the department to correct these deficiencies and to address modifications to facilities to bring them into compliance. The 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 estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of the Conroe site. Moreover, a third-party company has assumed the remediation costs associated with the Conroe site. Therefore, the Partnership does not expect to incur any material environmental liability associated with the Conroe site.

          (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 CCNG), our 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. The claim arises from a contract under which Crosstex CCNG processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex CCNG breached the contract by failing to build a processing plant of a certain size and design, resulting in Crosstex CCNG’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex CCNG failed to provide specific notices required under the contract. On December 4, 2007, and again on February 14, 2008, Denbury sent Crosstex CCNG letters demanding that its claim be arbitrated pursuant to an arbitration provision in the contract. Denbury subsequently requested that the parties attempt to mediate the matter before any arbitration proceeding is initiated. Although it is not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse impact on our consolidated results of operations or financial position.

(10) Partner’s Equity and Minority Interest

          Partner’s Equity represents the 2% general partner interest in CELP. Minority interest is comprised of the limited partner interests in CELP of $781.8 million, CELP’s accumulated other comprehensive income of ($21.5) million and the third party ownership interest in CELP’s CDC joint venture of $3.8 million.

(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 Seminole carbon dioxide processing plant located in Gaines County, Texas is included in the Treating division.

          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, 2007 are as follows (in thousands):

Midstream		$	2,337,081
Treating			214,481
Corporate			41,312
Total		$	2,592,874

(12) Condensed Consolidating Information

          The following table presents the condensed consolidating balance sheet data for the General Partner and CELP as of December 31, 2007 (in thousands):

		General								Consolidation
		Partner				CELP				Entries				Consolidated
Current assets		$	1			$	522,142			$	—			$	522,143
Property, plant and equipment, net			—				1,425,162				—				1,425,162
Fair value of derivative assets			—				1,337				—				1,337
Intangible assets, net			—				610,076				—				610,076
Goodwill			—				24,540				—				24,540
Investment in CELP			24,551				—				(24,551	)			—
Other assets, net			—				9,617				—				9,617
Total assets		$	24,552			$	2,592,874			$	(24,551	)		$	2,592,875
Current liabilities		$	—			$	569,030			$	—			$	569,030
Long-term debt			—				1,213,706				—				1,213,706
Other long-term liabilities			—				3,553				—				3,553
Deferred tax liability			—				8,518				—				8,518
Minority interest			—				3,815				760,275				764,090
Fair value of derivative liabilities			—				9,426				—				9,426
Partners’ equity			24,552				784,826				(784,826	)			24,552
Total liabilities and partners’ equity		$	24,552			$	2,592,874			$	(24,551	)		$	2,592,875