UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

CROSSTEX ENERGY, INC.

Delaware (State or other jurisdiction of incorporation or organization)		52-2235832 (I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS DALLAS, TEXAS (Address of principal executive offices)		75201 (Zip Code)

(214) 953-9500
(Registrant’s telephone number, including area code)

Title of Each Class		Name of Exchange on Which Registered
Common Stock, Par Value $0.01 Per Share		The NASDAQ Global Select Market

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $96,476,248 on June 30, 2009, based on $4.17 per share, the closing price of the Common Stock as reported on the NASDAQ Global Select Market on such date.

At February 16, 2010, there were 46,541,360 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Registrant’s Proxy Statement relating to its 2010 Annual Stockholders’ Meeting to be filed with the Securities and Exchange Commission are incorporated by reference herein into Part III of this Report.

 

 

TABLE OF CONTENTS
DESCRIPTION

Item		Page
PART I
1. BUSINESS			3
1A. RISK FACTORS			16
1B. UNRESOLVED STAFF COMMENTS			27
2. PROPERTIES			27
3. LEGAL PROCEEDINGS			28
4. RESERVED			28
PART II
5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			28
6. SELECTED FINANCIAL DATA			30
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			32
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			53
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			55
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			55
9A. CONTROLS AND PROCEDURES			55
9B. OTHER INFORMATION			56
PART III
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			56
11. EXECUTIVE COMPENSATION			57
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			57
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE			57
14. PRINCIPAL ACCOUNTING FEES AND SERVICES			57
PART IV
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			57
Exhibit 10.9
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1

CROSSTEX ENERGY, INC.

PART I

Item 1. Business

General

Crosstex Energy, Inc. is a Delaware corporation, formed in April 2000. We completed our initial public offering in January 2004. Our shares of common stock are listed on the NASDAQ Global Select Market under the symbol “XTXI”. Our executive offices are located at 2501 Cedar Springs, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.crosstexenergy.com. In the “Investors” section of our web site, we post the following filings as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual report on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our web site are available free of charge. In this report, the term “Crosstex Energy, Inc.” as well as the terms “our,” “we,” and “us,” or like terms, are sometimes used as references to Crosstex Energy, Inc. and its consolidated subsidiaries. References in this report to “Crosstex Energy, L.P.,” the “Partnership,” “CELP” or like terms refer to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. together with its consolidated subsidiaries.

CROSSTEX ENERGY, INC.

Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and natural gas liquids, or NGLs. These partnership interests consist of the following:

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16,414,830 common units representing an aggregate 25.0% limited partner interest in the Partnership as of January 31, 2010, and

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100.0% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.

The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

Prior to 2009, we received quarterly distributions from the Partnership with the last distribution for the fourth quarter of 2008 received in February 2009. During 2009, the Partnership’s ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions. Although the Partnership’s new credit facility should not limit its ability to make distributions during 2010 and in the future, any decision to resume cash distributions on its units and the amount of any such distributions would consider maintaining sufficient cash flow in excess of the distribution to continue to move the Partnership towards lower leverage ratios. The Partnership has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA (earnings before interest, income taxes, depreciation and amortization, non-cash mark-to-market items and other miscellaneous non-cash items) of less than 4.0 to 1.0, and the Partnership does not currently expect to resume cash distributions on its outstanding units until it achieves such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). The Partnership will also consider general economic conditions and its outlook for business as it determines to pay any distribution.

Since our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own, we do not expect to receive any significant cash flows until the Partnership is able to improve its leverage ratio and begin making distributions again. As of December 31, 2009, we have cash of $9.9 million which we expect to be sufficient to pay our expenses and federal income taxes and to fund our general partner contributions over the next several years based on our forecasted cash flows. We do not anticipate making any future dividend payments until we begin receiving distributions from the Partnership again.

Historically we have paid dividends to our stockholders on a quarterly basis equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

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federal income taxes, which we are required to pay because we are taxed as a corporation;

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the expenses of being a public company;

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other general and administrative expenses;

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capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s 2.0% general partner interest; and

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cash reserves our board of directors believed were prudent to maintain.

Our ability to pay dividends is limited by the Delaware General Corporation Law, which provides that a corporation may only pay dividends out of existing “surplus,” which is defined as the amount by which a corporation’s net assets exceeds its stated capital. While our ownership of the general partner and the common units of the Partnership are included in our calculation of net assets, the value of these assets may decline to a level where we have no “surplus,” thus prohibiting us from paying dividends under Delaware law.

So long as we own the Partnership’s general partner, under the terms of an omnibus agreement with the Partnership we are prohibited from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of a majority of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. The Partnership may elect to forego an opportunity for several reasons, including:

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the nature of some or all of the target’s assets or income might affect the Partnership’s ability to be taxed as a partnership for federal income tax purposes;

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the board of directors of Crosstex Energy GP, LLC, the general partner of the general partner of the Partnership, may conclude that some or all of the target assets are not a good strategic opportunity for the Partnership; or

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the seller may desire equity, rather than cash, as consideration or may not want to accept the Partnership’s units as consideration.

We have no present intention of engaging in additional operations or pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement, although we may decide to pursue them in the future, either alone or in combination with the Partnership. In the event that we pursue the types of opportunities that we are permitted to pursue under the omnibus agreement, our board of directors, in its sole discretion, may retain all, or a portion of, the cash distributions we receive on our partnership interests in the Partnership to finance all, or a portion of, such transactions, which may reduce or eliminate dividends paid to our stockholders.

CROSSTEX ENERGY, L.P.

Crosstex Energy, L.P. is an independent midstream energy company engaged in the gathering, transmission, processing and marketing of natural gas and NGLs. It connects the wells of natural gas producers in its market areas to its gathering systems, processes natural gas for the removal of NGLs, fractionates NGLs into purity products and markets those products for a fee, transports natural gas and ultimately provides natural gas to a variety of markets. It purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipelines. It operates processing plants that process gas transported to the plants by major interstate pipelines or from its own gathering systems under a variety of fee arrangements. In addition, it purchases natural gas from producers not connected to its gathering systems for resale and sells natural gas on behalf of producers for a fee.

As generally used in the energy industry and in this document, the following terms have the following meanings:

/d = per day
Bbls = barrels
Bcf = billion cubic feet
Btu = British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid

Capacity volumes for the Partnership’s facilities are measured based on physical volume and stated in cubic feet (Bcf, Mcf or MMcf). Throughput volumes are measured based on energy content and stated in British thermal units (Btu or MMBtu). A volume capacity of 100 MMcf generally correlates to volume throughput of 100,000 MMBtu.

Operations of the Partnership

The Partnership focuses on the gathering, processing, transmission and marketing of natural gas and NGLs. Its combined midstream assets consist of over 3,300 miles of natural gas gathering and transmission pipelines, nine natural gas processing plants and three fractionators located in two primary regions: north Texas and Louisiana. Its gathering systems consist of a network of pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. The Partnership’s transmission pipelines primarily receive natural gas from its gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Its processing plants remove NGLs from a natural gas stream and its fractionators separate the NGLs into separate NGL products, including ethane, propane, iso- and normal butanes and natural gasoline.

The Partnership assets include the following:

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North Texas Assets. The North Texas Assets are comprised of gathering, processing and transmission assets serving producers active in the Barnett Shale. The gathering systems in north Texas consist of approximately 600 miles of gathering lines with total capacity of approximately 1,100 MMcf/d and total throughput of approximately 793,000 MMBtu/d for the year ended December 31, 2009. Processing facilities in north Texas include three gas processing plants with a total processing capacity of 280 MMcf/d. Total processing throughput averaged 219,000 MMBtu/d for the year ended December 31, 2009. Transmission assets consist of a 140-mile pipeline from an area near Fort Worth, Texas to a point near Paris, Texas, and related facilities. The capacity on the North Texas Pipeline, or NTP, is approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos, Gulf Crossing and other markets. For the year ended December 31, 2009, the total throughput on the NTP was approximately 318,000 MMBtu/d.

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Crosstex LIG System. The Crosstex LIG system is one of the largest intrastate pipeline systems in Louisiana, consisting of approximately 2,100 miles of gathering and transmission pipeline, with an average total throughput of approximately 900,000 MMBtu/d for the year ended December 31, 2009. The system also includes two operating, on-system processing plants, Plaquemine and Gibson, with an average throughput of approximately 269,000 MMBtu/d for the year ended December 31, 2009. The system has access to both rich and lean gas supplies. These supplies reach from the Haynesville Shale in north Louisiana to new onshore production in south central and southeast Louisiana. Crosstex LIG has a variety of transportation and industrial sales customers, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.

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South Louisiana Processing and NGL Assets. The Partnership’s south Louisiana natural gas processing and liquids assets include a total of 2.0 Bcf/d of processing capacity, 66,000 Bbls/d of fractionation capacity, 2.4 million barrels of underground storage and approximately 400 miles of liquids transport lines. The assets include the Eunice processing plant and fractionation facility; the Pelican, Sabine and Blue Water processing plants; the Riverside fractionation plant; the Napoleonville storage facility; the Cajun Sibon pipeline system and the Intracoastal Pipeline. Total processing throughput averaged 856,000 MMBtu/d during December 2009. The Eunice plant is connected to onshore gas supply, as well as continental shelf and deepwater gas production. The Pelican and Sabine plants are connected with continental shelf and deepwater gas. The various plants have downstream connections to the ANR Pipeline, Florida Gas Transmission, Texas Gas Transmission, Tennessee Gas Pipeline and Transco.

Business Strategy

From the inception of the Partnership in 2002 until the second half of 2008, the Partnership’s long-term strategy had been to increase distributable cash flow per unit by accomplishing economies of scale through new construction or expansion in core operating areas and making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas and NGLs. In response to volatility in the commodity and capital markets over the last 18 months and other events, including the substantial decline in commodity prices, the Partnership adjusted its business strategy in the fourth quarter 2008 and in 2009 to focus on maximizing liquidity, improving the balance sheet through debt reduction and other methods, maintaining a stable asset base, improving the profitability of its assets by increasing their utilization while controlling costs and reducing capital expenditures. Consistent with this strategy, the Partnership divested non-core assets since October 2008 for aggregate sale proceeds of $618.7 million and substantially reduced its outstanding debt. During 2010 the Partnership plans to continue its focus on (i) improving existing system profitability, (ii) continuing to improve the balance sheet and financial flexibility and (iii) pursuing strategic acquisitions and undertaking selective construction and expansion opportunities. Key elements of the strategy will include the following:

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Improve existing system profitability. The Partnership intends to operate its existing asset base to enhance profitability by continuing initiatives to maximize utilization by improving operations, reducing operating costs and renegotiating contracts, when appropriate, to improve economics. The Partnership has a solid base of assets that are well located to benefit from the continued growth in the Barnett Shale in north Texas and the new growth anticipated from the Haynesville Shale located in northern Louisiana. It markets services directly to both producers and end users in order to connect new supplies of natural gas, contract new end user deliveries, improve margins and manage operations to fully utilize its systems’ capacities. As part of this process, the Partnership focuses on providing a full range of services to producers and end users, including supply aggregation and transportation and hedging, which it believes provides a competitive advantage when competing for sources of natural gas supply.

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Continue to improve the balance sheet and financial flexibility. The Partnership intends to continue to improve its balance sheet and financial flexibility. It has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA (earnings before interest, income taxes, depreciation and amortization, non-cash mark-to-market items and other miscellaneous non-cash items) of less than 4.0 to 1.0, and it does not currently expect to resume cash distributions on its outstanding units until it achieves such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). In addition, any decision to resume cash distributions on partnership units and the amount of any such distributions would consider maintaining sufficient cash flow in excess of the distribution to continue to move towards lower leverage levels. The Partnership will also consider general economic conditions and the outlook for its business as it determines to pay any distribution. The Partnership’s 2010 capital expenditure budget includes approximately $25.0 million of identified growth projects, and it expects to fund such expenditures with internally generated cash flow, with any excess cash flow applied towards debt, working capital or new projects. The Partnership will also consider the use of alternative financing strategies such as entering into joint venture arrangements. As of February 12, 2010, after repayment of existing debt and borrowings under new debt agreements in January and early February 2010 discussed under “Recent Developments,” the Partnership has approximately $193.1 million of available capacity for additional borrowings and potential letters of credit under its new credit facility. The Partnership believes that availability under its new credit facility, its ability to issue additional partnership units and enter into strategic joint venture arrangements should provide it with the financial flexibility to facilitate the execution of its business strategy.

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Pursue strategic acquisitions and undertake selective construction and expansion opportunities (“organic growth”).

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The Partnership intends to use its acquisition and integration experience to continue to make strategic acquisitions of assets that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of the acquired asset. It pursues acquisitions that it believes will add to existing core areas in order to capitalize on existing infrastructure, personnel and producer and consumer relationships. The Partnership also examines opportunities to establish positions in new areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas, primarily through the acquisition or development of key assets that will serve as a platform for further growth.

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The Partnership also intends to leverage its existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for gathering, transmission, processing and marketing services. Substantially all of its capital projects during 2009 and its planned projects for 2010 target these types of opportunities.

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The Partnership will consider the construction of facilities and systems in new areas in regions with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas that lack midstream infrastructure to process and/or transport the natural gas. It believes its existing infrastructure and construction experience provide a competitive advantage for such expansion opportunities. For example:

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The Partnership established a new core area through the acquisition of LIG Pipeline Company and subsidiaries, which is collectively referred to as Crosstex LIG, in 2004, thereby acquiring one of the largest intrastate pipeline systems in Louisiana. As a result of this acquisition, in 2006 and 2007 the Partnership had the opportunity to expand the system in north Louisiana in response to increasing production from the Cotton Valley formation, from a capacity of approximately 40 MMcf/d to approximately 275 MMcf/d. It further expanded the system in north Louisiana during 2008 and 2009, increasing its capacity to 410 MMcf/d as of December 31, 2009 to take advantage of the increasing production and producer needs in the Haynesville Shale.

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In 2006, the Partnership established a new core area in north Texas by adding the natural gas gathering pipeline systems and related facilities acquired from Chief Holdings LLC, or Chief, to its NTP, and other operations in the Barnett Shale area. Immediately prior to the acquisition, the Partnership had completed construction on its NTP. Since the 2006 acquisition, the Partnership has expanded its gathering system in north Texas and connected in excess of 500 new wells and significantly increased acreage dedicated to its systems. The Partnership has also constructed three gas processing plants with total processing capacity in the Barnett Shale of 280 MMcf/d.

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In 2005, the Partnership acquired the south Louisiana processing business from El Paso Corporation, which included a lease of the Eunice NGL processing plant and fractionation facility. In October 2009, it acquired the Eunice NGL processing plant and fractionation facility, which will eliminate $12.2 million per year in lease expense and provide opportunities for optimization of the facility. In December 2009, the Partnership acquired the Intracoastal Pipeline, which it was using under a lease arrangement and which is integrated with its NGL system in south Louisiana. Not only will the acquisition of the Intracoastal Pipeline eliminate lease expense, but at the time of the acquisition the partnership also received additional dedications of liquids volumes into its systems from another operator in the area.

Recent Developments

In the fourth quarter of 2008, the Partnership adjusted its business strategy to focus on maximizing liquidity, reducing debt, maintaining a stable asset base, improving the profitability of assets by increasing their utilization while controlling costs and reducing capital expenditures. The Partnership is successfully executing its plan as highlighted by the following accomplishments:

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Sold Non-Core Assets. The Partnership sold $618.7 million of non-core assets and repaid approximately $500.0 million in long-term indebtedness from the sales proceeds over the last 15 months. In November 2008, the Partnership sold its 12.4% interest in the Seminole gas processing plant for $85.0 million. In the first quarter of 2009, the Partnership sold its Arkoma system for approximately $10.7 million. In August 2009, the Partnership sold its midstream assets in Alabama, Mississippi and south Texas for approximately $217.6 million. In addition, in October 2009, the Partnership sold its natural gas treating business for $265.4 million. The Partnership also sold its east Texas midstream assets on January 15, 2010 for $40.0 million.

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Reduced Capital Expenditures. The Partnership reduced its capital expenditures from over $275.6 million in 2008 to $101.4 million in 2009 and focused its capital projects on lower risk projects with higher expected returns.

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Reduced Operating and General and Administrative Expenses. The Partnership reduced its operating expenses from continuing operations to $110.4 million for the year ended December 31, 2009 from $125.8 million for the year ended December 31, 2008 and general and administrative expenses from continuing operations to $59.9 million for the year ended December 31, 2009 from $68.9 million for the year ended December 31, 2008 by reducing staffing and controlling costs. General and administrative expenses for the year ended December 31, 2009 also include non-recurring costs totaling $4.4 million associated with severance payments, lease termination costs and bad debt expense due to the SemStream, L.P. bankruptcy.

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Acquired Certain Assets in Our Core Areas. The Partnership acquired the Eunice NGL processing plant and fractionation facility in October 2009 for $23.5 million in cash and the assumption of $18.1 million in debt. It originally acquired the contract rights associated with the Eunice plant as part of the south Louisiana acquisition in November 2005 and operated and managed the plant under an operating lease with an unaffiliated third party prior to the recent acquisition. This acquisition will eliminate lease obligations of $12.2 million per year. The Partnership also acquired the Intracoastal Pipeline located in southern Louisiana for approximately $10.3 million in December 2009. Both of these acquisitions were designed to enhance its NGL business.

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Sale of Preferred Units. On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions. The 14,705,882 preferred units are convertible at any time into common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. The Partnership has the right to force conversion of the preferred units after three years, subject to certain conditions. The preferred units are not redeemable but will pay a quarterly distribution that will be the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units.

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Issuance of Senior Unsecured Notes. On February 10, 2010, the Partnership issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes due 2018 (the “notes” or “senior unsecured notes”) at an issue price of 97.907% to yield 9.25% to maturity. Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and original issue discount), together with borrowings under its new credit facility discussed below, were used to repay in full amounts outstanding under the existing bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with the existing credit facility. The notes are unsecured and unconditionally guaranteed on a senior basis by certain of the Partnership’s direct and indirect subsidiaries, including substantially all of its current subsidiaries. Interest payments will be paid semi-annually in arrears starting in August 2010. The Partnership has the option to redeem all or a portion of the notes at any time on or after February 15, 2014, at the specified redemption prices. Prior to February 15, 2014, it may redeem the notes, in whole or in part, at a “make-whole” redemption price. In addition, it may redeem up to 35% of the notes prior to February 15, 2013 with the cash proceeds from certain equity offerings.

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New Credit Facility. In February 2010, the Partnership amended and restated its existing secured bank credit facility with a new syndicated secured bank credit facility (the “new credit facility”), which will be guaranteed by substantially all of its subsidiaries. The new credit facility has a borrowing capacity of $420.0 million, and matures in February 2014. Obligations under the new credit facility will be secured by first priority liens on substantially all of the Partnership assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of its equity interests in substantially all of its subsidiaries. Under the new credit facility, borrowings will bear interest at the Partnership’s option at the British Bankers Association LIBOR Rate plus an applicable margin, or the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate, in each case plus an applicable margin. The Partnership will pay a per annum fee on all letters of credit issued under the new credit facility, and it will pay a commitment fee of 0.50% per annum on the unused availability under the new credit facility. The letter of credit fee and the applicable margins for its interest rate vary quarterly based on its leverage ratio.

Partnership Assets

North Texas Assets. The Partnership’s NTP which commenced service in April 2006, consists of a 140-mile pipeline and associated gathering lines from an area near Fort Worth, Texas to a point near Paris, Texas. The initial capacity of the NTP was approximately 250 MMcf/d. In 2007, the capacity on the NTP was expanded to a total of approximately 375 MMcf/d. The NTP connects production from the Barnett Shale to markets in north Texas and to markets accessed by the Natural Gas Pipeline Company, or NGPL, Kinder Morgan, Houston Pipeline, or HPL, Atmos, Gulf Crossing and other markets. For the year ended December 31, 2009, the total throughput on the NTP was approximately 318,000 MMBtu/d. The new interconnect with Gulf Crossing Pipeline, which commenced service in August 2009, provides customers access to mid-west and east coast markets.

On June 29, 2006, the Partnership acquired the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.3 million. The acquired systems included gathering pipelines, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that transaction, approximately 160,000 net acres previously owned by Chief and acquired by Devon simultaneously with the acquisition, as well as 60,000 net acres owned by other producers, were dedicated to the systems. Immediately following the closing of the Chief acquisition, the Partnership began expanding its north Texas gathering system.

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Gathering System. Since the date of the acquisition through December 31, 2009, the Partnership expanded its gathering system and connected in excess of 500 new wells to the north Texas gathering system and significantly increased the productive acreage dedicated to the system. As of December 31, 2009, total capacity on the north Texas gathering system was approximately 1,100 MMcf/d and total throughput averaged approximately 793,000 MMBtu/d for the year ended December 31, 2009.

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Processing Facilities. Since 2006, the Partnership has constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including the Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, the Azle plant, which is a 50 MMcf/d cryogenic processing plant and the Goforth plant, which is a 30 MMcf/d processing plant. Total processing throughput averaged 219,000 MMBtu/d for the year ended December 31, 2009.

The Partnership has budgeted approximately $15.0 million for continued development of its north Texas assets during 2010.

These capital projects represent system expansions that are planned to handle volume growth as well as projects required pursuant to existing obligations with producers to connect new wells to its gathering systems in north Texas.

Louisiana Assets. The Partnership’s Louisiana assets include its Crosstex LIG intrastate pipeline system and its gas processing and liquids business in south Louisiana, referred to as the south Louisiana processing assets.

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Crosstex LIG System. The Crosstex LIG system is one of the largest intrastate pipeline systems in Louisiana, consisting of approximately 2,100 miles of gathering and transmission pipeline, with an average throughput of approximately 900,000 MMBtu/d for the year ended December 31, 2009. The system also includes two operating, on-system processing plants, the Plaquemine and Gibson plants, with an average throughput of 269,000 MMBtu/d for the year ended December 31, 2009. The system has access to both rich and lean gas supplies. These supplies reach from north Louisiana to new onshore production in south central and southeast Louisiana. Crosstex LIG has a variety of transportation and industrial sales customers, with the majority of its sales being made into the industrial Mississippi River corridor between Baton Rouge and New Orleans.

In 2007, the Partnership extended the Crosstex LIG system to the north to reach additional productive areas in the developing natural gas fields south of Shreveport, Louisiana, primarily in the Cotton Valley formation. This extension, referred to as the north Louisiana expansion, consists of 63 miles of 24” mainline with 9 miles of gathering lateral pipeline. The north Louisiana expansion bisects the developing Haynesville Shale gas play in north Louisiana. The north Louisiana expansion was operating at near capacity during 2008 as the Haynesville gas was beginning to develop so the Partnership added 35 MMcf/d of capacity by adding compression during the third quarter of 2008 bringing the total capacity of the north Louisiana expansion to approximately 275 MMcf/d. The Partnership continued the expansion of its north Louisiana system during 2009 increasing capacity by 100 MMcf/d in July 2009 by adding compression. It increased capacity by another 35 MMcf/d with a new interconnect into an interstate pipeline in December 2009 and bringing total capacity to 410 MMcf/d by the end of 2009. The Partnership has long-term firm transportation agreements subscribing to all of the incremental capacity added during 2009. In addition, it added compression during 2009 between the southern portion of the Crosstex LIG system and the northern expansion of the Crosstex LIG system, which increased the capacity for moving gas from the north LIG system to markets in the south to 145 MMcf/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission, Trunkline Gas and Tennessee Gas Pipeline.

The Partnership has budgeted approximately $10.0 million to add an additional 30 MMcf/d of fully contracted capacity in north Louisiana during 2010.

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South Louisiana Processing and NGL Assets. Natural gas processing capacity available to the Gulf Coast producers continues to exceed demand. During 2007, 2008, and 2009 the Partnership completed a number of operational changes at its Eunice facility and other plants to idle certain equipment, reduce operating expenses and reconfigure operations to manage the lower utilization. In addition, the Partnership increased focus on upstream markets and opportunities through integration of the Crosstex LIG system and south Louisiana processing assets to improve overall performance. In 2008, its south Louisiana assets were negatively impacted by hurricanes Gustav and Ike, which came ashore in September 2008. Although the Partnership assets did not sustain substantial physical damage, several offshore platforms and pipelines owned by third parties transporting gas production to Pelican, Eunice, Sabine Pass and Blue Water processing plants were damaged by the storms. Substantially all of the production from the pipeline systems supplying Partnership plants was restored to pre-hurricane levels by September 2009. The south Louisiana processing assets include the following:

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Eunice Processing Plant and Fractionation Facility. The Eunice processing plant is located in south central Louisiana, has a capacity of 750 MMcf/d and processed approximately 380,000 MMBtu/d during December 2009. The plant is connected to onshore gas supply, as well as continental shelf and deepwater gas production and has downstream connections to the ANR Pipeline, Florida Gas Transmission and Texas Gas Transmission, or TGT. The Eunice fractionation facility, which was idled in August 2007, has a capacity of 36,000 barrels per day of liquid products. Beginning in August 2007, the liquids from the Eunice processing plant were transported through the Cajun Sibon pipeline system to the Riverside plant for fractionation. The Eunice fractionation facility, when operational, produces ethane, propane, iso-butane, normal butane and natural gasoline for various customers. The fractionation facility is directly connected to the southeast propane market and pipelines to the Anse La Butte storage facility. The Partnership owned the contract rights associated with the Eunice plant and operated and managed the plant under an operating lease with an unaffiliated third party through October 2009. In October 2009, it acquired the Eunice plant for $23.5 million in cash and the assumption of $18.1 million in debt by buying out the operating lease, thereby eliminating $12.2 million of annual lease obligations.

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Pelican Processing Plant. The Pelican processing plant complex is located in Patterson, Louisiana and has a designed capacity of 600 MMcf/d of natural gas. During December 2009, the plant processed approximately 340,000 MMBtu/d. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline.

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Sabine Pass Processing Plant. The Sabine Pass processing plant is located east of the Sabine River at Johnson’s Bayou, Louisiana and has a processing capacity of 300 MMcf/d of natural gas. The Sabine Pass plant is connected to continental shelf and deepwater gas production with downstream connections to Florida Gas Transmission, Tennessee Gas Pipeline (TGP) and Transco. The plant processed approximately 107,000 MMBtu/d during December 2009.

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Blue Water Gas Processing Plant. The Partnership acquired a 23.85% interest in the Blue Water gas processing plant in the November 2005 El Paso acquisition and acquired an additional 35.42% interest in May 2006, at which time it became the operator of the plant. The plant has a net capacity to the Partnership’s interest of 186 MMcf/d. During 2008, TGP acquired Columbia Gulf Transmission’s ownership share in the Blue Water pipeline. In January 2009, TGP reversed the flow of the gas on the pipeline thereby removing access to all the gas processed at the Blue Water plant from the Blue Water offshore system and the plant did not operate during the nine months ended September 30, 2009. In November 2009, the plant was restarted to process the reverse flow stream on TGP. The gas composition of the reverse TGP stream is leaner in NGL content, but may be profitable to process during periods of high fractionation spreads. The plant is expected to operate in this mode periodically as fractionation spread and volumes dictate. When the reverse stream is processed, the Partnership earns all of the margin from processing the gas under a straddle agreement with TGP.

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Riverside Fractionation Plant. The Riverside fractionator and loading facility is located on the Mississippi River upriver from Geismar, Louisiana. The Riverside plant has a fractionation capacity of approximately 30,000 Bbls/d of liquids products and fractionates liquids delivered by the Cajun Sibon pipeline system from the Eunice, Pelican and Blue Water plants or by truck. The Riverside facility has above-ground storage capacity of approximately 102,000 barrels.

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Napoleonville Storage Facility. The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of approximately 2.4 million barrels of underground storage from two existing caverns. The caverns are currently operated in propane and butane service and space is sold to customers for a fee.

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Cajun Sibon Pipeline System. The Cajun Sibon pipeline system consists of approximately 400 miles of 6” and 8” pipelines with a system capacity of approximately 28,000 Bbls/d. The pipeline transports unfractionated NGLs, referred to as raw make, from the Eunice, Pelican and Blue Water plants to either the Riverside fractionator or to third party fractionators when necessary. Alternate deliveries can be made to the Eunice fractionation facility when operational.

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Intracoastal Pipeline. In December 2009, the Partnership acquired the Intracoastal Pipeline from a subsidiary of Chevron Midstream Pipelines LLC. The pipeline consists of approximately 62 miles of six and eight inch pipeline and extends from Patterson to Henry in southern Louisiana. The pipeline connects the Pelican processing plant to the Cajun Sibon pipeline system and accesses other third party processing plants in the region. Prior to the Partnership’s acquisition, it utilized portions of the Intracoastal Pipeline under a long-term lease arrangement. This acquisition eliminates approximately $1.3 million of annual lease expense. The Partnership has also entered into an agreement to use the system to bring additional liquids into its NGL system.

Industry Overview

The following diagram illustrates the gathering, processing, fractionation and transmission process.

The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-user markets. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

Natural gas gathering. The natural gas gathering process follows the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.

Compression. Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Because wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it will be unable to overcome the higher gathering system pressure. In contrast, if field compression is installed, a declining well can continue delivering natural gas.

Natural gas processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of NGLs and contaminants, such as water, sulfur compounds, nitrogen or helium. Natural gas produced by a well may not be suitable for long-haul pipeline transportation or commercial use and may need to be processed to remove the heavier hydrocarbon components and contaminants. Natural gas in commercial distribution systems is composed almost entirely of methane and ethane, with moisture and other contaminants removed to very low concentrations. Natural gas is processed not only to remove unwanted contaminants that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream, as well as the removal of contaminants.

NGL fractionation. Fractionation is the process by which NGLs are further separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel and industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutene through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock.

Natural gas transmission. Natural gas transmission pipelines receive natural gas from mainline transmission pipelines, processing plants, and gathering systems and deliver it to industrial end-users, utilities and to other pipelines.

Balancing of Supply and Demand

As the Partnership purchases natural gas, it establishes a margin normally by selling natural gas for physical delivery to third-party users. It can also use over-the-counter derivative instruments or enter into a future delivery obligation under futures contracts on the NYMEX. Through these transactions, the Partnership seeks to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Its policy is not to acquire and hold natural gas futures contracts or derivative products for the purpose of speculating on price changes.

Competition

The business of providing gathering, transmission, processing and marketing services for natural gas and NGLs is highly competitive. The Partnership faces strong competition in obtaining natural gas supplies and in the marketing and transportation of natural gas and NGLs. Its competitors include major integrated oil companies, natural gas producers, interstate and intrastate pipelines and other natural gas gatherers and processors. Competition for natural gas supplies is primarily based on geographic location of facilities in relation to production or markets, the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer. Many of the Partnership’s competitors offer more services or have greater financial resources and access to larger natural gas supplies than it does. The competition differs in different geographic areas.

In marketing natural gas and NGLs, the Partnership has numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and local and national natural gas producers, gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with the Partnership’s marketing operations.

The Partnership faces strong competition for acquisitions and development of new projects from both established and start-up companies. Competition increases the cost to acquire existing facilities or businesses, and results in fewer commitments and lower returns for new pipelines or other development projects. Many of its competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. The Partnership’s competition differs by region and by the nature of the business or the project involved.

Natural Gas Supply

The Partnership’s transmission pipelines have connections with major interstate and intrastate pipelines, which it believes have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of its gathering systems, the Partnership evaluates well and reservoir data publicly available or furnished by producers or other service providers to determine the availability of natural gas supply for the systems and/or obtain a minimum volume commitment from the producer that results in a rate of return on investment. Based on these facts, the Partnership believes that there should be adequate natural gas supply to recoup its investment with an adequate rate of return. The Partnership does not routinely obtain independent evaluations of reserves dedicated to its systems due to the cost and relatively limited benefit of such evaluations. Accordingly, it does not have estimates of total reserves dedicated to its systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

The Partnership is diligent in attempting to ensure that it issues credit to only credit-worthy customers. However, the purchase and resale of gas exposes it to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to overall profitability.

During the year ended December 31, 2009, the Partnership had one customer that accounted for approximately 12.2% of consolidated revenues from continuing operations. While this customer represents a significant percentage of consolidated revenues, the loss of this customer would not have a material impact on results of operations.

Regulation

Regulation by FERC of Interstate Natural Gas Pipelines. The Partnership does not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or FERC, does not directly regulate its operations under the National Gas Act, or NGA. However, FERC’s regulation of interstate natural gas pipelines influences certain aspects of the Partnership’s business and the market for its products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

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the certification and construction of new facilities;

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the extension or abandonment of services and facilities;

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the maintenance of accounts and records;

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the acquisition and disposition of facilities;

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maximum rates payable for certain services; and

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the initiation and discontinuation of services.

While the Partnership does not own any interstate pipelines, it does transport gas in interstate commerce. The rates, terms and conditions of service under which the Partnership transports natural gas in its pipeline systems in interstate commerce is subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. In addition, FERC has adopted, or is in the process of adopting, various regulations concerning natural gas market transparency that will apply to some of the pipeline operations. The maximum rates for services provided under Section 311 of the NGPA may not exceed a “fair and equitable rate”, as defined in the NGPA. The rates are generally subject to review every three years by FERC or by an appropriate state agency. The inability to obtain approval of rates at acceptable levels could result in refund obligations, the inability to achieve adequate returns on investments in new facilities and the deterrence of future investment or growth of the regulated facilities.

Intrastate Pipeline Regulation. The Partnership’s intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. The Partnership owns a number of natural gas pipelines that it believes meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.

The Partnership is subject to some state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.

Sales of Natural Gas. The price at which the Partnership sells natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Its sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The Partnership cannot predict the ultimate impact of these regulatory changes on its natural gas marketing operations but does not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.

Environmental Matters

General. The Partnership’s operation of processing and fractionation plants, pipelines and associated facilities in connection with the gathering and processing of natural gas and the transportation, fractionation and storage of NGLs is subject to stringent and complex federal, state and local laws and regulations relating to release of hazardous substances or wastes into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases its overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines and other facilities. Included in the Partnership’s construction and operation costs are capital cost items necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon any future acquisition of operating assets.

Any failure to comply with applicable environmental laws and regulations, including those relating to obtaining required governmental approvals, may result in the assessment of administrative, civil or criminal penalties, imposition of investigatory or remedial activities and, in less common circumstances, issuance of injunctions or construction bans or delays. We believe that the Partnership currently holds all material governmental approvals required to operate its major facilities. As part of the regular overall evaluation of its operations, the Partnership has implemented procedures to review and update governmental approvals as necessary. We believe that the Partnership’s operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on its operating results or financial condition.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with the Partnership’s possible future operations, and we cannot assure you that the Partnership will not incur significant costs and liabilities, including those relating to claims for damage to property and persons as a result of any such upsets, releases, or spills. In the event of future increases in environmental costs, the Partnership may be unable to pass on those cost increases to its customers. A discharge of hazardous substances or wastes into the environment could, to the extent losses related to the event are not insured, subject the Partnership to substantial expense, including both the cost to comply with applicable laws and regulations and to pay fines or penalties that may be assessed and the cost related to claims made by neighboring landowners and other third parties for personal injury or damage to property. The Partnership will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to comply with changing environmental laws and regulations and to minimize costs.

Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting the Partnership’s operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to prevent and control pollution. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous wastes, and may require investigatory and corrective actions at facilities where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of “hazardous substance” into the environment. Potentially liable persons include the owner or operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the potentially responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of future, ordinary operations, the Partnership may generate wastes that may fall within the definition of a “hazardous substance.” However, there are other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, the Partnership may be responsible under CERCLA or other laws for all or part of the costs required to clean up sites at which such wastes have been disposed. The Partnership has not received any notification that it may be potentially responsible for cleanup costs under CERCLA or any analogous federal or state laws.

The Partnership also generates, and may in the future generate, both hazardous and nonhazardous solid wastes that are subject to requirements of the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The Partnership is not currently required to comply with a substantial portion of the RCRA requirements because its operations generate minimal quantities of hazardous wastes. From time to time, the Environmental Protection Agency, or EPA, has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated by it that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Changes in applicable regulations may result in an increase in the Partnership’s capital expenditures or plant operating expenses.

The Partnership currently owns or leases, and has in the past owned or leased, and in the future may own or lease, properties that have been used over the years for natural gas gathering, treating or processing and for NGL fractionation, transportation or storage. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and other solid wastes have been disposed of on or under various properties owned or leased by the Partnership during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom the Partnership had no control as to such entities’ handling of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, the Partnership could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, or to take action to prevent future contamination.

Air Emissions. The Partnership’s current and future operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including the Partnership’s facilities, and impose various monitoring and reporting requirements. Pursuant to these laws and regulations, the Partnership may be required to obtain environmental agency pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing air emissions, obtain and comply with the terms of air permits, which include various emission and operational limitations, or use specific emission control technologies to limit emissions. The Partnership likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with maintaining or obtaining governmental approvals addressing air-emission related issues. Failure to comply with applicable air statutes or regulations may lead to the assessment of administrative, civil or criminal penalties, and may result in the limitation or cessation of construction or operation of certain air emission sources. Although we can give no assurances, we believe such requirements will not have a material adverse effect on the Partnership’s financial condition or operating results, and the requirements are not expected to be more burdensome to the Partnership than any similarly situated company.

Air emissions associated with operations in the Barnett Shale area have come under recent scrutiny. In 2009, the Texas Commission on Environmental Quality (TCEQ) conducted comprehensive monitoring of air emissions in the Barnett Shale area, in response to public concerns about high concentrations of benzene in the air near drilling sites and natural gas processing facilities. A comprehensive report detailing the monitoring results and their potential health impacts is expected to be finalized in early 2010. Environmental groups have advocated increased regulation in the Barnett Shale area and these groups as well as at least one state representative have further advocated a moratorium on permits for new gas wells until TCEQ completes its analysis. Also, the EPA recently entered into a settlement that requires it to reevaluate regulations for the control of air emissions from natural gas production facilities. Changes in laws or regulations imposing emission limitations, pollution control technology requirements or other regulatory requirements or any restriction on permitting of natural gas production facilities in the Barnett Shale area could have an adverse effect on the Partnership’s business.

Climate Change. In response to concerns suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” (including carbon dioxide and methane), may be contributing to warming of the Earth’s atmosphere, the U.S. Congress is actively considering legislation to reduce such emissions. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures intended to reduce greenhouse gas emissions, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. In addition, EPA is taking steps that would result in the regulation of greenhouse gases as pollutants under the federal Clean Air Act. Furthermore, in September 2009, EPA finalized regulations that require monitoring and reporting of greenhouse gas emissions on an annual basis, including extensive greenhouse gas monitoring and reporting requirements, beginning in 2010. Although the greenhouse gas reporting rule does not control greenhouse gas emission levels from any facilities, it will still cause the Partnership to incur monitoring and reporting costs for emissions that are subject to the rule. Some of the Partnership’s facilities include source categories that are subject to the greenhouse gas reporting requirements included in the final rule. However, EPA postponed a decision on proposed Subpart W to 40 CFR part 98, which would have applied to fugitive and vented methane emissions from the oil and gas sector, including natural gas transmission compression. The prospect remains that EPA will adopt regulations that require reporting of fugitive and vented methane emissions from the oil and gas industry, which will increase the Partnership’s monitoring and reporting costs. In December 2009, EPA also issued findings that greenhouse gases in the atmosphere endanger public health and welfare, and that emissions from mobile sources cause or contribute to greenhouse gases in the atmosphere. The endangerment findings will not immediately affect the Partnership’s operations, but standards eventually promulgated pursuant to these findings could affect its operations and ability to obtain air permits for new or modified facilities. Legislation and regulations relating to control or reporting of greenhouse gas emissions are also in various stages of discussions or implementation in about one-third of the states. Lawsuits have been filed seeking to force the federal government to regulate greenhouse gases emissions under the Clean Air Act and to require individual companies to reduce greenhouse gas emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact the Partnership’s operations and ability to obtain certifications and permits to construct future projects.

Passage of climate change legislation or other federal or state legislative or regulatory initiatives that regulate or restrict emissions of greenhouse gases in areas in which the Partnership conducts business could adversely affect the demand for the products it stores, transports and processes, and depending on the particular program adopted could increase the costs of its operations, including costs to operate and maintain its facilities, install new emission controls on its facilities, acquire allowances to authorize its greenhouse gas emissions, pay any taxes related to its greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. The Partnership may be unable to recover any such lost revenues or increased costs in the rates it charges its customers, and any such recovery may depend on events beyond its control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or regulations. Reductions in the Partnership’s revenues or increases in its expenses as a result of climate control initiatives could have adverse effects on its business, financial position, results of operations and prospects.

Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid related wastes, into state waters or waters of the United States. Regulations promulgated pursuant to these laws require that entities that discharge into federal and state waters obtain National Pollutant Discharge Elimination System, or NPDES, and/or state permits authorizing these discharges. The Clean Water Act and analogous state laws assess administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and impose substantial liability for the costs of removing spills from such waters. In addition, the Clean Water Act and analogous state laws require that individual permits or coverage under general permits be obtained by covered facilities for discharges of storm water runoff. The Partnership believes that it is in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that continued compliance with such existing permit conditions will not have a material effect on its results of operations.

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is an important and commonly used process in the completion of wells by the Partnership’s customers, particularly in Barnett Shale and Haynesville Shale regions of its operations. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In particular, the U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for the Partnership’s customers to perform hydraulic fracturing. Any increased federal, state or local regulation could reduce the volumes of natural gas that the Partnership’s customers move through its gathering systems which would materially adversely affect its revenues and results of operations.

Employee Safety. The Partnership is subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. The Partnership believes that its operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Safety Regulations. The Partnership’s pipelines are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act, as amended, or HLPSA, and the Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192, effective February 14, 2004 relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines) amendment to 49 CFR Part 192 (PIM) requires operators of gas transmission pipelines to ensure the integrity of their pipelines through hydrostatic pressure testing, the use of in-line inspection tools or through risk-based direct assessment techniques. In addition, the Railroad Commission of Texas, or TRRC, regulates the Partnership’s pipelines in Texas under its own pipeline integrity management rules. The Texas rule includes certain transmission and gathering lines based upon pipeline diameter and operating pressures. The Partnership believes that its pipeline operations are in substantial compliance with applicable HLPSA and PIM requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA or PIM requirements will not have a material adverse effect on its results of operations or financial positions.

Office Facilities

We occupy approximately 95,400 square feet of space at our executive offices in Dallas, Texas under a lease expiring in June 2014, approximately 25,100 square feet of office space for the Partnership’s south Louisiana operations in Houston, Texas with lease terms expiring in January 2013 and approximately 11,800 square feet of office space for its north Texas operations in Fort Worth, Texas, with lease terms expiring in April 2013.

Employees

As of December 31, 2009, the Partnership (through its subsidiaries) employed approximately 456 full-time employees. Approximately 244 of the employees were general and administrative, engineering, accounting and commercial personnel and the remainders were operational employees. The Partnership is not party to any collective bargaining agreements, and has not had any significant labor disputes in the past. We believe that the Partnership has good relations with its employees.

Item 1A. Risk Factors

The following risk factors and all other information contained in this report should be considered carefully when evaluating us. These risk factors could affect our actual results. Other risks and uncertainties, in addition to those that are described below, may also impair our business operations. If any of the following risks occur, our business, financial condition or results of operations could be affected materially and adversely. In that case, we may be unable to pay dividends to our shareholders and the trading price of our common shares could decline. These risk factors should be read in conjunction with the other detailed information concerning us set forth in our accompanying financial statements and notes and contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included herein.

Our cash flow consists almost exclusively of distributions from Crosstex Energy, L.P.

Our only cash-generating assets are our partnership interests in Crosstex Energy, L.P. Our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners. Prior to 2009, we received quarterly distributions from the Partnership with the last distribution for the fourth quarter of 2008 received in February 2009. During 2009, the Partnership’s ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions. Although the Partnership’s new credit facility should not limit its ability to make distributions during 2010 and in the future, any decision to resume cash distributions on its units and the amount of any such distributions would consider maintaining sufficient cash flow in excess of the distribution to continue to move the Partnership towards lower leverage ratios. The Partnership has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA of less than 4.0 to 1.0, and the Partnership does not currently expect to resume cash distributions on its outstanding units until it achieves such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). The Partnership will also consider general economic conditions and its outlook for business as it determines to pay any distribution.

The Partnership may not have sufficient available cash each quarter to pay distributions to unitholders. The amount of cash that the Partnership can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things:

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the amount of natural gas transported in its gathering and transmission pipelines;

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the level of the Partnership’s processing operations;

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the fees the Partnership charges and the margins it realizes for its services;

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the price of natural gas;

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the relationship between natural gas and NGL prices; and

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its level of operating costs;

In addition, the actual amount of cash the Partnership will have available for distribution will depend on other factors, some of which are beyond its control, including:

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the level of capital expenditures the Partnership makes;

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the cost of acquisitions, if any;

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its debt service requirements;

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fluctuations in its working capital needs;

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its ability to make working capital borrowings under its bank credit facility to pay distributions;

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prevailing economic conditions; and

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the amount of cash reserves established by the general partner in its sole discretion for the proper conduct of its business.

Because of these factors, the Partnership may not be able, or may not have sufficient available cash to pay distributions to unitholders each quarter. Furthermore, you should also be aware that the amount of cash the Partnership has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.

We are largely prohibited from engaging in activities that compete with the Partnership.

So long as we own the general partner of the Partnership, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity. This exception for competitive activities is relatively limited. Although we have no current intention of pursuing the types of opportunities that we are permitted to pursue under the omnibus agreement such as competitive opportunities that the Partnership declines to pursue or permitted activities that are not competition with the Partnership, the provisions of the omnibus agreement may, in the future, limit activities that we would otherwise pursue.

In our corporate charter, we have renounced business opportunities that may be pursued by the Partnership or by certain stockholders.

In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to:

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persons who are officers or directors of the company or who, on October 1, 2003, were, and at the time of presentation are, stockholders of the company (or to persons who are affiliates or associates of such officers, directors or stockholders), if the company is prohibited from participating in such opportunities by the omnibus agreement; or

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any investment fund sponsored or managed by Yorktown Partners LLC, including any fund still to be formed, or to any of our directors who is an affiliate or designate of these entities.

As a result of this renunciation, these officers, directors and stockholders should not be deemed to be breaching any fiduciary duty to us if they or their affiliates or associates pursue opportunities presented as described above.

Although we control the Partnership, the general partner owes fiduciary duties to the Partnership and the unitholders.

Conflicts of interest exist and may arise in the future as a result of the relationship between us and our affiliates, including the general partner, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of Crosstex Energy GP, LLC have fiduciary duties to manage the general partner in a manner beneficial to us, its owner. At the same time, the general partner has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and its limited partners. The board of directors of Crosstex Energy GP, LLC will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our stockholders.

For example, conflicts of interest may arise in the following situations:

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the allocation of shared overhead expenses to the Partnership and us;

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and the Partnership, on the other hand, including obligations under the omnibus agreement;

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the determination of the amount of cash to be distributed to the Partnership’s partners and the amount of cash to be reserved for the future conduct of the Partnership’s business;

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the determination whether to make borrowings under the capital facility to pay distributions to partners; and

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any decision we make in the future to engage in activities in competition with the Partnership as permitted under our omnibus agreement with the Partnership.

If the general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of the Partnership, its value, and therefore the value of our common stock, could decline.

The general partner may make expenditures on behalf of the Partnership for which it will seek reimbursement from the Partnership. In addition, under Delaware partnership law, the general partner, in its capacity as the general partner of the Partnership, has unlimited liability for the obligations of the Partnership, such as its debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the general partner. To the extent the general partner incurs obligations on behalf of the Partnership, it is entitled to be reimbursed or indemnified by the general partner. In the event that the Partnership is unable or unwilling to reimburse or indemnify the general partner, the general partner may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common stock.

The Partnership’s profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile.

The Partnership’s business is subject to significant risks due to fluctuations in commodity prices. It is directly exposed to these risks primarily in the gas processing component of its business. It is also indirectly exposed to commodity prices due to the negative impacts on production and the development of production of natural gas and NGLs connected to or near its assets and on its margins for transportation between certain market centers. A large percentage of its processing fees are realized under percent of liquids (POL) contracts that are directly impacted by the market price of NGLs. It also realizes processing gross margins under processing margin (margin) contracts. These settlements are impacted by the relationship between NGL prices and the underlying natural gas prices, which is also referred to as the fractionation spread.

A significant volume of inlet gas at the Partnership’s south Louisiana and north Texas processing plants is settled under POL agreements. The POL fees are denominated in the form of a share of the liquids extracted and it is not responsible for the fuel or shrink associated with processing. Therefore, revenue under a POL agreement is directly impacted by NGL prices, and the decline of these prices in the second half of 2008 and early 2009 contributed to a significant decline in the Partnership’s gross margin from processing.

The Partnership has a number of contracts on its Plaquemine and Gibson processing plants that expose it to the fractionation spread. Under these margin contracts its gross margin is based upon the difference in the value of NGLs extracted from the gas less the value of the product in its gaseous state (“shrink”) and the cost of fuel to extract during processing. During the second half of 2008 and early 2009, the fractionation spread narrowed significantly as the value of NGLs decreased more than the value of the gas and fuel associated with the processed gas. Thus the gross margin realized under these margin contracts was negatively impacted due to the commodity price environment. Such a decline may negatively impact its gross margin in the future if such declines again.

In the past, the prices of natural gas and NGLs have been extremely volatile and the Partnership expects this volatility to continue. For example, prices of oil, natural gas and NGLs in 2009 were below the market price realized throughout most of 2008. Crude oil prices (based on the New York Mercantile Exchange (the “NYMEX”) futures daily close prices for the prompt month) improved during 2009 with prices ranging from a low of $33.98 per Bbl in February 2009 to a high of $81.37 per Bbl in October 2009. Weighted average NGL prices (based on the Oil Price Information Service (OPIS) Mt. Belvieu daily average spot liquids prices) have also improved with prices ranging from a low of $0.58 per gallon in March 2009 to a high of $1.21 per gallon in December 2009. Natural gas prices declined during 2009 with prices ranging from a high of $6.10 per MMBtu in January 2009 to a low of $1.85 per MMBtu in September 2009. Natural gas prices improved during the fourth quarter of 2009, with prices reaching a high of $6.00 per MMBtu in December 2009.

The markets and prices for natural gas and NGLs depend upon factors beyond the Partnership’s control. These factors include the supply and demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

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the impact of weather on the demand for oil and natural gas;

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the level of domestic oil and natural gas production;

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technology, including improved production techniques (particularly with respect to shale development);

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the level of domestic industrial and manufacturing activity;

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the availability of imported oil, natural gas and NGLs;

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international demand for oil and NGLs;

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actions taken by foreign oil and gas producing nations;

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the availability of local, intrastate and interstate transportation systems;

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the availability of downstream NGL fractionation facilities;

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the availability and marketing of competitive fuels;

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the impact of energy conservation efforts; and

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the extent of governmental regulation and taxation, including the regulation of “greenhouse gases.”

Changes in commodity prices may also indirectly impact the Partnership’s profitability by influencing drilling activity and well operations, and thus the volume of gas it can gather and process. This volatility may cause the Partnership’s gross margin and cash flows to vary widely from period to period. Hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of the Partnership’s throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “—The Partnership’s use of derivative financial instruments does not eliminate its exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduced income.” For a discussion of the Partnership’s risk management activities, please read “Item 7A. Qualitative and Quantitative Disclosure about Market Risk.”

The Partnership’s substantial indebtedness could limit its flexibility and adversely affect its financial health.

The Partnership has a substantial amount of indebtedness. As of December 31, 2009, the Partnership had approximately $873.7 million of indebtedness outstanding. As of February 12, 2010, after repayment of existing debt with proceeds from the sale of preferred units together with proceeds from the issuance of its senior unsecured notes and borrowings under its new credit facility, the Partnership had approximately $790.6 million (including $15.2 million of original issue discount on the senior unsecured notes) of indebtedness outstanding, including $725.0 million of senior unsecured notes and $47.5 million of secured indebtedness outstanding under our new credit facility and $18.1 million of series B secured note associated with the Eunice lease acquisition. The Partnership also had approximately $179.4 million of letters of credit outstanding under its old credit facility as of February 12, 2010 that were subsequently replaced by letters of credit under the new credit facility.

The Partnership’s substantial indebtedness could limit its flexibility and adversely affect its financial health. For example, it could:

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make the Partnership more vulnerable to general adverse economic and industry conditions;

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require the Partnership to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flow for operations and other purposes;

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limit the Partnership’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and

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place the Partnership at a competitive disadvantage compared to competitors that may have proportionately less indebtedness.

In addition, the Partnership’s ability to make scheduled payments or to refinance obligations depends on its successful financial and operating performance. The Partnership cannot assure you that its operating performance will generate sufficient cash flow or that its capital resources will be sufficient for payment of its indebtedness obligations in the future. The Partnership’s financial and operating performance, cash flow and capital resources depend upon prevailing economic conditions and certain financial, business and other factors, many of which are beyond its control.

If the Partnership’s cash flow and capital resources are insufficient to fund its debt service obligations, the Partnership may be forced to sell material assets or operations, obtain additional capital or restructure its debt. In the event that the Partnership is required to dispose of material assets or operations or restructure its debt to meet debt service and other obligations, it cannot assure you as to the terms of any such transaction or how quickly any such transaction could be completed, if at all.

The Partnership may not be able to obtain additional funding for future capital needs or to refinance its debt, either on acceptable terms or at all.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile, which has caused substantial contraction in the credit and capital markets. These conditions, along with significant write-offs in the financial services sector and current weak economic conditions, have made, and will likely continue to make, it difficult to obtain funding for the Partnership’s capital needs. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. Due to these factors, the Partnership cannot be certain that new debt or equity financing will be available to it on acceptable terms or at all. If funding is not available when needed, or is available only on unfavorable terms, the Partnership may be unable to meet its obligations as they come due. Without adequate funding, the Partnership may be unable to execute its growth strategy, complete future acquisitions or future construction projects or other capital expenditures, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on its revenues and results of operations. Further, its customers may increase collateral requirements from the Partnership, including letters of credit which reduce available borrowing capacity, or reduce the business they transact with the Partnership to reduce their credit exposure.

Due to current economic conditions, the Partnership’s ability to obtain funding under its new credit facility could be impaired.

The Partnership operates in a capital-intensive industry and relies on its new credit facility to assist in financing a significant portion of its capital expenditures. The Partnership’s ability to borrow under its new credit facility may be impaired. Specifically, the Partnership may be unable to obtain adequate funding under its new credit facility because:

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one or more of the Partnership’s lenders may be unable or otherwise fail to meet its funding obligations;

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the lenders do not have to provide funding if there is a default under the credit agreement or if any of the representations or warranties included in the agreement are false in any material respect; and

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if any lender refuses to fund its commitment for any reason, whether or not valid, the other lenders are not required to provide additional funding to make up for the unfunded portion.

If the Partnership is unable to access funds under its new credit facility, the Partnership will need to meet its capital requirements, including some of its short-term capital requirements, using other sources. Alternative sources of liquidity may not be available on acceptable terms, if at all. If the cash generated from its operations or the funds the Partnership is able to obtain under its new credit facility or other sources of liquidity are not sufficient to meet its capital requirements, then it may need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on its results of operations and financial condition.

Due to the Partnership’s lack of asset diversification, adverse developments in its gathering, transmission, processing and producer services businesses would materially impact its financial condition.

The Partnership relies exclusively on the revenues generated from its gathering, transmission, processing and producer services businesses and as a result its financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to its lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on its financial condition and results of operations than if the Partnership maintained more diverse assets.

Many of the Partnership’s customers’ drilling activity levels and spending for transportation on its pipeline system or gathering and processing at its facilities have been, and may continue to be, impacted by the current deterioration in the credit markets.

Many of the Partnership’s customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. During the last half of 2008 and during 2009, there was a significant decline in the credit markets and the availability of credit. Adverse price changes, coupled with the overall downturn in the economy and the constrained capital markets, put downward pressure on drilling budgets for gas producers, which has resulted in lower volumes that the Partnership otherwise would have seen being transported on its pipeline and gathering systems and processing through its processing plants. The Partnership saw a decline in drilling activity by gas producers in its Barnett Shale area of operation in north Texas during the fourth quarter of 2008 and during 2009. A continued decline in drilling activity or low drilling activity could have a material adverse effect on its operations.

The Partnership is exposed to the credit risk of its customers and counterparties, and a general increase in the nonpayment and nonperformance by its customers could have an adverse effect on its financial condition and results of operations.

Risks of nonpayment and nonperformance by the Partnership’s customers are a major concern in its business. The Partnership is subject to risks of loss resulting from nonpayment or nonperformance by its customers and other counterparties, such as lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by its customers could adversely affect the results of operations and reduce the Partnership’s ability to make distributions to its unitholders. Many of the Partnership’s customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of the Partnership’s customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in customers’ liquidity and ability to make payment or perform on their obligations to the Partnership. Furthermore, some of the customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to the Partnership.

The Partnership’s use of derivative financial instruments does not eliminate its exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduced income.

The Partnership’s operations expose it to fluctuations in commodity prices, and its new credit facility exposes the Partnership to fluctuations in interest rates. The Partnership uses over-the-counter price and basis swaps with other natural gas merchants and financial institutions and interest rate swaps with financial institutions. Use of these instruments is intended to reduce its exposure to short-term volatility in commodity prices and interest rates. As of December 31, 2009, the Partnership had hedged only portions of its variable-rate debt and expected natural gas supply, NGL production and natural gas requirements, and had direct interest rate and commodity price risk with respect to the unhedged portions. In addition, to the extent the Partnership hedges its commodity price and interest rate risks using swap instruments, it will forego the benefits of favorable changes in commodity prices or interest rates. In February 2010, the Partnership settled all of its interest rate swaps associated with its existing credit facility when the Partnership repaid the debt outstanding under this facility.

Even though monitored by management, the Partnership’s hedging activities may fail to protect it and could reduce earnings and cash flow. Its hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:

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hedging can be expensive, particularly during periods of volatile prices;

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the Partnership’s counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and

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available hedges may not correspond directly with the risks against which the Partnership seeks protection. For example:

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the duration of a hedge may not match the duration of the risk against which the Partnership seeks protection;

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variations in the index used to price a commodity hedge may not adequately correlate with variations in the index used to sell the physical commodity (known as basis risk); and

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the Partnership may not produce or process sufficient volumes to cover swap arrangements it enters into for a given period. If its actual volumes are lower than the volumes it estimated when entering into a swap for the period, the Partnership might be forced to satisfy all or a portion of its derivative obligation without the benefit of cash flow from its sale or purchase of the underlying physical commodity, which could adversely affect liquidity.

The Partnership’s financial statements may reflect gains or losses arising from exposure to commodity prices or interest rates for which it is unable to enter into fully effective hedges. In addition, the standards for cash flow hedge accounting are rigorous. Even when the Partnership engages in hedging transactions that are effective economically, these transactions may not be considered effective cash flow hedges for accounting purposes. Partnership earnings could be subject to increased volatility to the extent its derivatives do not continue to qualify as cash flow hedges, and, if the Partnership assumes derivatives as part of an acquisition, to the extent it cannot obtain or choose not to seek cash flow hedge accounting for the derivatives it assumes. Please read “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” for a summary of the Partnership’s hedging activities.

The Partnership may not be successful in balancing its purchases and sales.

The Partnership is a party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that the Partnership has under contract may decline due to reduced drilling or other causes and it may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could purchase more or less than contracted volumes. Any of these actions could cause the Partnership’s purchases and sales not to be balanced. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in operating income.

The Partnership makes certain commitments to purchase natural gas in production areas based on production-area indices and to sell the natural gas into market areas based on market-area indices, pay the costs to transport the natural gas between the two points and capture the difference between the indices as margin. Changes in the index prices relative to each other (also referred to as basis spread) can significantly affect the Partnership’s margins or even result in losses. For example, the Partnership is a party to one contract where it buys gas on several different production-area indices on its NTP and sells the gas into a different market area index. For the fourth quarter of 2009, this imbalance resulted in a loss of approximately $1.8 million due to basis differentials between the various market prices.

The Partnership must continually compete for natural gas supplies, and any decrease in its supplies of natural gas could adversely affect its financial condition and results of operations.

If the Partnership is unable to maintain or increase the throughput on its systems by accessing new natural gas supplies to offset the natural decline in reserves, its business and financial results could be materially, adversely affected. In addition, the Partnership’s future growth will depend, in part, upon whether it can contract for additional supplies at a greater rate than the rate of natural decline in its currently connected supplies.

In order to maintain or increase throughput levels in the Partnership’s natural gas gathering systems and asset utilization rates at the Partnership’s processing plants and to fulfill its current sales commitments, it must continually contract for new natural gas supplies. The Partnership may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting its ability to connect new wells to its gathering facilities include the Partnership’s success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near its gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. For example, as oil and natural gas prices decreased during the last half of 2008 and the first half of 2009, there was a corresponding decrease in drilling activity. Tax policy changes or additional regulatory restrictions on development could also have a negative impact on drilling activity, reducing supplies of natural gas available to the Partnership’s systems. The Partnership has no control over producers and depends on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production or in the level of drilling activity in the Partnership’s principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on results of operations and financial position.

The Partnership is vulnerable to operational, regulatory and other risks due to its concentration of assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.

The Partnership’s operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because it has a significant portion of its assets located in south Louisiana and the Gulf of Mexico. In 2008, the Partnership’s business was negatively impacted by hurricanes Gustav and Ike, which came ashore in the Gulf Coast in September. These storms resulted in an adverse impact to the Partnership’s gross margins of approximately $22.9 million in the last half of 2008. Although the Partnership’s assets did not sustain substantial physical damage, several offshore production platforms and pipelines owned by third parties that transport gas production to our Pelican, Eunice, Sabine Pass and Blue Water processing plants in south Louisiana were damaged by the storms. Some of the repairs to these offshore facilities were completed during the fourth quarter of 2008, but gas production to the Partnership’s south Louisiana plants did not recover to pre-hurricane levels until September 2009.

The Partnership’s concentration of activity in Louisiana and the Gulf of Mexico makes it more vulnerable than many of its competitors to the risks associated with these areas, including:

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adverse weather conditions, including hurricanes and tropical storms;

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delays or decreases in production, the availability of equipment, facilities or services; and

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changes in the regulatory environment.

Because a significant portion of the Partnership’s operations could experience the same condition at the same time, these conditions could have a relatively greater impact on its results of operations than they might have on other midstream companies who have operations in more diversified geographic areas.

In addition, the Partnership’s operations in south Louisiana are dependent upon continued conventional and deep shelf drilling in the Gulf of Mexico. The deep shelf in the Gulf of Mexico is an area that has had limited historical drilling activity. This is due, in part, to its geological complexity and depth. Deep shelf development is more expensive and inherently more risky than conventional shelf drilling. A decline in the level of deep shelf drilling in the Gulf of Mexico could have an adverse effect on the Partnership’s financial condition and results of operations.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by the Partnership’s customers, which could adversely impact its revenues.

The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells by our customers, particularly in Barnett Shale and Haynesville Shale regions of the Partnership’s operations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for our customers to perform hydraulic fracturing. Many producers make extensive use of hydraulic fracturing in the areas that the Partnership serves and any increased federal, state or local regulation could reduce the volumes of natural gas that they move through the Partnership’s gathering systems which would materially adversely affect revenues and results of operations.

A substantial portion of the Partnership’s assets are connected to natural gas reserves that will decline over time, and the cash flows associated with those assets will decline accordingly.

A substantial portion of the Partnership’s assets, including its gathering systems, is dedicated to certain natural gas reserves and wells for which the production will naturally decline over time. Accordingly, cash flows associated with these assets will also decline. If the Partnership is unable to access new supplies of natural gas either by connecting additional reserves to its existing assets or by constructing or acquiring new assets that have access to additional natural gas reserves, cash flows may decline.

Growing the Partnership’s business by constructing new pipelines and processing facilities subjects it to construction risks, risks that natural gas supplies will not be available upon completion of the facilities and risks of construction delay and additional costs due to obtaining rights-of-way and complying with federal, state and local laws.

One of the ways the Partnership intends to grow its business is through the construction of additions to our existing gathering systems and construction of new pipelines and gathering and processing facilities. The construction of pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our expectations. Generally, the Partnership may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, it may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. The Partnership may also rely on estimates of proved reserves in its decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve the expected investment return, which could adversely affect the Partnership’s results of operations and financial condition. In addition, the Partnership faces the risks of construction delay and additional costs due to obtaining rights-of-way and local permits and complying with federal or state laws and city ordinances, particularly as the Partnership expands its operations into more urban, populated areas such as the Barnett Shale.

Acquisitions typically increase the Partnership’s debt and subjects it to other substantial risks, which could adversely affect its results of operations.

From time to time, the Partnership may evaluate and seek to acquire assets or businesses that it believes complement existing business and related assets. The Partnership may acquire assets or businesses that it plans to use in a manner materially different from their prior owner’s use. Any acquisition involves potential risks, including:

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the inability to integrate the operations of recently acquired businesses or assets;

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the diversion of management’s attention from other business concerns;

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the loss of customers or key employees from the acquired businesses;

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a significant increase in the Partnership’s indebtedness; and

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potential environmental or regulatory liabilities and title problems.

Management’s assessment of these risks is necessarily inexact and may not reveal or resolve all existing or potential problems associated with an acquisition. Realization of any of these risks could adversely affect the Partnership’s operations and cash flows. If Partnership consummates any future acquisition, its capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that the Partnership will consider in determining the application of these funds and other resources.

Additionally, the Partnership’s ability to grow its asset base in the near future through acquisitions may be limited due to its lack of access to capital markets.

The Partnership expects to encounter significant competition in any new geographic areas into which it seeks to expand and its ability to enter such markets may be limited.

If the Partnership expands its operations into new geographic areas, it expects to encounter significant competition for natural gas supplies and markets. Competitors in these new markets will include companies larger than the Partnership, which have both lower capital costs and greater geographic coverage, as well as smaller companies, which have lower total cost structures. As a result, the Partnership may not be able to successfully develop acquired assets and markets located in new geographic areas and its results of operations could be adversely affected.

The Partnership may not be able to retain existing customers or acquire new customers, which would reduce its revenues and limit its future profitability.

The renewal or replacement of existing contracts with the Partnership’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets the Partnership serves. The inability of the Partnership’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on its profitability.

In particular, the Partnership’s ability to renew or replace its existing contracts with industrial end-users and utilities impacts its profitability. For the year ended December 31, 2009, approximately 48.5% of the Partnership’s sales of natural gas that was transported using its physical facilities were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with the Partnership in the marketing of natural gas, the Partnership often competes in the end-user and utilities markets primarily on the basis of price.

The Partnership depends on certain key customers, and the loss of any of its key customers could adversely affect its financial results.

The Partnership derives a significant portion of its revenues from contracts with key customers. To the extent that these and other customers may reduce volumes of natural gas purchased or transported under existing contracts, the Partnership would be adversely affected unless it was able to make comparably profitable arrangements with other customers. Certain agreements with key customers provide for minimum volumes of natural gas or natural gas services that require the customer to transport, process or purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Customers may default on their obligations to transport, process or purchase the minimum volumes of natural gas or natural gas services required under the applicable agreements.

The Partnership’s business involves many hazards and operational risks, some of which may not be fully covered by insurance.

The Partnership’s operations are subject to the many hazards inherent in the gathering, compressing, processing and storage of natural gas and NGLs, including:

•

damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;

•

inadvertent damage from construction and farm equipment;

•

leaks of natural gas, NGLs and other hydrocarbons; and

•

fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of the Partnership’s related operations. The Partnership is not fully insured against all risks incident to its business. In accordance with typical industry practice, the Partnership does not have any property insurance on any of it underground pipeline systems that would cover damage to the pipelines. It is not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect the Partnership’s operations and financial condition.

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact the Partnership’s results of operations and its ability to raise capital.

Terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. The Partnership’s insurance policies generally exclude acts of terrorism. Such insurance is not available at what it believes to be acceptable pricing levels.

Federal, state or local regulatory measures could adversely affect the Partnership’s business.

The Partnership’s natural gas gathering and processing activities generally are exempt from FERC regulation under the Natural Gas Act. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels since FERC has less extensively regulated the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. The Partnership’s gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Partnership cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

The rates, terms and conditions of service under which the Partnership transports natural gas in its pipeline systems in interstate commerce are subject to FERC regulation under the Section 311 of the Natural Gas Policy Act. Under these regulations, the Partnership is required to justify its rates for interstate transportation service on a cost-of-service basis, every three years. The Partnership’s intrastate natural gas pipeline operations are subject to regulation by various agencies of the states in which they are located. Should FERC or any of these state agencies determine that the Partnership’s rates for Section 311 transportation service or intrastate transportation service should be lowered, its business could be adversely affected.

Other state and local regulations also affect the Partnership’s business. It is subject to some ratable take and common purchaser statutes in the states where it operate. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting the Partnership’s right as an owner of gathering facilities to decide with whom it will contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which the Partnership operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which the Partnership operates that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

The states in which the Partnership conducts operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of its gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns, or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future, and it does not apply to the Partnership’s natural gas transmission pipelines. In response to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements.

Compliance with pipeline integrity regulations issued by the United States Department of Transportation in December 2003 or those issued by the TRRC could result in substantial expenditures for testing, repairs and replacement. TRRC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. The Partnership’s costs relating to compliance with the required testing under the TRRC regulations, adjusted to exclude costs associated with discontinued operations, were approximately at $1.1 million, $1.4 million, and $0.1 million for the years ended December 31, 2009, 2008, and 2007, respectively. The Partnership expects the costs for compliance with TRRC and DOT regulations to be approximately $3.7 million during 2010. If the Partnership’s pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then it may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

As the Partnership’s operations continue to expand into and around urban, or more populated areas, such as the Barnett Shale, it may incur additional expenses to mitigate noise, odor and light that may be emitted in its operations, and expenses related to the appearance of its facilities. Municipal and other local or state regulations are imposing various obligations, including, among other things, regulating the location of our facilities, imposing limitations on the noise levels of the Partnership’s facilities and requiring certain other improvements that increase the cost of its facilities. The Partnership is also subject to claims by neighboring landowners for nuisance related to the construction and operation of its facilities, which could subject it to damages for declines in neighboring property values due to its construction and operation of facilities.

The Partnership’s business involves hazardous substances and may be adversely affected by environmental regulation.

Many of the operations and activities of the Partnership’s gathering systems, processing plants, fractionators and other facilities are subject to significant federal, state and local environmental laws and regulations. The obligations imposed by these laws and regulations include obligations related to air emissions and discharge of pollutants from facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by the Partnership or locations to which it has sent wastes for treatment or disposal. Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Strict, joint and several liability may be incurred under these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties near the Partnership’s facilities or upon or through which the Partnership’s gathering systems traverse, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations for releases of contaminants or for personal injury or property damage.

There is inherent risk of the incurrence of significant environmental costs and liabilities in the Partnership’s business due to its handling of natural gas and other petroleum substances, air emissions related to its operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters containing mercury. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. The Partnership may incur material environmental costs and liabilities. Furthermore, its insurance may not provide sufficient coverage in the event an environmental claim is made against it.

The Partnership’s business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental laws or regulations, including, for example, legislation being considered by the U.S. Congress relating to the control of greenhouse gas emissions or changes in existing environmental laws or regulations might adversely affect products and activities, including processing, storage and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect the Partnership’s profitability. Changes in laws or regulations could also limit production or the operation of the Partnership’s assets or adversely affect its ability to comply with applicable legal requirements or the demand for natural gas, which could adversely affect business and the Partnership’s profitability.

The Partnership’s success depends on key members of its management, the loss or replacement of whom could disrupt business operations.

The Partnership depends on the continued employment and performance of the officers of the general partner of its general partner and key operational personnel. The general partner of its general partner has entered into employment agreements with each of its executive officers. If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, the Partnership’s business operations could be materially adversely affected. The Partnership does not maintain any “key man” life insurance for any officers.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 2. Properties

A description of the Partnership’s properties is contained in “Item 1. Business.”

Title to Properties

Substantially all of the Partnership’s pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. The Partnership has obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which the Partnership’s pipeline was built was purchased in fee. The Partnership’s processing plants are located on land that it leases or owns in fee.

We believe that the Partnership has satisfactory title to all of its rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of the Partnership’s assets or from the Partnership’s interest in these assets or should materially interfere with their use in the operation of the business.

Item 3. Legal Proceedings

Our operations and those of the Partnership are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we or the Partnership may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, property use or damage and personal injury. Additionally, as the Partnership continues to expand operations into more urban, populated areas, such as the Barnett Shale, it may see an increase in claims brought by area landowners, such as nuisance claims and other claims based on property rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial results or our operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

In December 2008, Denbury Onshore, LLC (“Denbury”) initiated formal arbitration proceedings against Crosstex CCNG Processing Ltd. (“Crosstex Processing”), Crosstex Energy Services, L.P. (“Crosstex Energy”), Crosstex North Texas Gathering, L.P. (“Crosstex Gathering”) and Crosstex Gulf Coast Marketing, Ltd. (“Crosstex Marketing”), all wholly-owned subsidiaries of the Partnership, asserting a claim for breach of contract under a gas processing agreement. Denbury alleged damages in the amount of $16.2 million, plus interest and attorneys’ fees. Crosstex denied any liability and sought to have the action dismissed. A three-person arbitration panel conducted a hearing on the merits in December 2009. At the close of the evidence at the hearing, the panel granted judgment for Crosstex on one of Denbury’s claims, and on February 16, 2010, the panel granted judgment for Denbury on its remaining claims in the amount of $3.0 million plus interest, attorneys’ fees and costs. The panel will conduct additional proceedings to determine the amount of attorneys’ fees and costs, if any, that should be awarded to Denbury. We estimate that the total award will be between $3.0 million and $4.0 million at the conclusion of these additional proceedings and a liability for this award was accrued as of December 31, 2009.

At times, the Partnership’s gas-utility subsidiaries acquire pipeline easements and other property rights by exercising rights of eminent domain provided under state law. As a result, the Partnership (or its subsidiaries) is a party to a number of lawsuits under which a court will determine the value of pipeline easements or other property interests obtained by the Partnership’s gas utility subsidiaries by condemnation. Damage awards in these suits should reflect the value of the property interest acquired and the diminution in the value of the remaining property owned by the landowner. However, some landowners have alleged unique damage theories to increase their damage claims or assert valuation methodologies that could result in damage awards in excess of the amounts anticipated. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not expect that awards in these matters will have a material adverse impact on its consolidated results of operations or financial condition.

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

On July 22, 2008, 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 $2.3 million for July 2008 sales. The Partnership believes the July sales of $2.3 million will receive “administrative claim” status in the bankruptcy proceeding. The debtor’s schedules acknowledge its obligation to Crosstex for an administrative claim in the amount of $2.3 million, but it remains subject to an objection by the lenders’ agent. The Partnership evaluated these receivables for collectibility and recorded a provision for bad debt of $3.1 million during the year ended December 31, 2008 and $0.8 million during the year ended December 31, 2009.

Item 4. Reserved

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the NASDAQ Global Select Market under the symbol “XTXI”. Our common stock began trading on January 12, 2004. On February 16, 2010, the closing market price for our common stock was $7.75 per share and there were approximately 13,500 record holders and beneficial owners (held in street name) of the shares of our common stock.

The following table shows the high and low closing sales prices per share, as reported by the NASDAQ Global Select Market, for the periods indicated:

		Common Stock
		Price Range								Cash Dividends
		High				Low				Paid per Share
2009:
Quarter Ended December 31		$	6.57			$	4.13				—
Quarter Ended September 30			5.60				3.13				—
Quarter Ended June 30			5.40				1.79				—
Quarter Ended March 31			6.71				0.79				—
2008:
Quarter Ended December 31		$	20.93			$	2.19			$	0.090
Quarter Ended September 30			34.13				24.26				0.320
Quarter Ended June 30			36.79				33.54				0.380
Quarter Ended March 31			37.37				31.55				0.360

Historically, we have paid to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

•

federal income taxes, which we are required to pay because we are taxed as a corporation;

•

the expenses of being a public company;

•

other general and administrative expenses;

•

capital contributions to the Partnership upon the issuance by it of additional partnership securities in order to maintain the general partner’s 2.0% general partner interest; and

•

reserves our board of directors believes prudent to maintain.

The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. Prior to 2009, we received quarterly distributions from the Partnership with the last distribution for the fourth quarter of 2008 received in February 2009. During 2009, the Partnership’s ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions. Although the Partnership’s new credit facility does not limit its ability to make distributions as long as the Partnership is not in default of its facility (and the indenture governing its senior unsecured notes requires it to meet a ratio test), any decision to resume cash distributions on its units and the amount of any such distributions would consider maintaining sufficient cash flow in excess of the distribution to continue to move the Partnership towards lower leverage ratios. The Partnership has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA of less than 4.0 to 1.0, and the Partnership does not currently expect to resume cash distributions on its outstanding units until it achieves such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). The Partnership will also consider general economic conditions and its outlook for business as it determines to pay any distribution. We do not anticipate making any future dividend payments until we begin receiving distributions from the Partnership again.

Performance Graph

The following graph sets forth the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Stock Index, and a peer group of publicly traded partners of publicly traded limited partnerships in the Midstream natural gas, natural gas liquids and propane industries from January 12, 2004, the date of our initial public offering, through December 31, 2009. The chart assumes that $100 was invested on January 12, 2004, with dividends reinvested. The peer group includes Atlas Pipeline Holdings, L.P., Inergy Holdings, L.P., Enterprise GP Holdings, L.P., Alliance Holdings GP, L.P. and Magellan Midstream Holdings, L.P. (Inergy Holdings, L.P.’s initial public offering was in June 2005, Enterprise GP Holdings L.P.’s initial public offering was in August 2005, Atlas Pipeline Holdings, L.P.’s initial public offering was in July 2006, Alliance Holdings GP, L.P.’s initial public offering was in May 2006, and Magellan Midstream Holdings, L.P.’s initial public offering was in February 2006, and it has been assumed that these companies performed in accordance with the peer group average prior to such dates).

Item 6. Selected Financial Data

The following table sets forth selected historical financial and operating data of Crosstex Energy, Inc. as of and for the dates and periods indicated. The revised selected historical financial data are derived from the audited financial statements of Crosstex Energy, Inc. and have been revised to reflect 2009 asset disposition as discontinued operations and to move letter of credit fees to interest expense and from purchased gas expense. The summary historical financial and operating data include the results of operations, the south Louisiana processing assets beginning November 2005, the NTP beginning April 2006, the midstream assets acquired from Chief beginning June 2006 and other smaller acquisitions completed during 2006.

The table should be read together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

		Crosstex Energy, Inc.
		Years Ended December 31,
		2009				2008				2007				2006				2005
		(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Midstream		$	1,453,346			$	3,072,646			$	2,380,224			$	1,534,800			$	1,212,864
Gas and NGL marketing activities			5,744				3,365				4,105				2,535				1,599
Total revenues			1,459,090				3,076,011				2,384,329				1,537,335				1,214,463
Operating costs and expenses:
Purchased gas			1,147,868				2,768,225				2,124,503				1,378,979				1,154,345
Operating expenses			110,394				125,762				91,236				65,916				28,989
General and administrative			62,491				72,377				62,270				45,724				32,141
(Gain) loss on derivatives			(2,994	)			(8,619	)			(4,147	)			(174	)			10,399
Gain on sale of property			(666	)			(947	)			(1,024	)			(1,936	)			(8,289	)
Impairments			2,894				30,177				—				—				—
Depreciation and amortization			119,162				107,652				83,361				56,410				15,168
Total operating costs and expenses			1,439,149				3,094,627				2,356,199				1,544,919				1,232,753
Operating income (loss)			19,941				(18,616	)			28,130				(7,584	)			(18,290	)
Other income:
Interest expense, net			(95,078	)			(74,861	)			(47,649	)			(19,512	)			(11,972	)
Loss on extinguishment of debt			(4,669	)			—				—				—				—
Other income			1,449				27,898				538				1,802				391
Total other income (expense)			(98,298	)			(46,963	)			(47,111	)			(17,710	)			(11,581	)
Loss from continuing operations before income taxes and gain on issuance of Partnership units			(78,357	)			(65,579	)			(18,981	)			(25,294	)			(29,871	)
Income tax benefit (provision)			6,020				1,375				(6,319	)			(7,833	)			(23,095	)
Gain on issuance of Partnership units(1)			—				14,748				7,461				18,955				65,070
Income (loss) from continuing operations before cumulative effect of change in accounting principle, net of tax			(72,337	)			(49,456	)			(17,839	)			(14,172	)			12,104
Discontinued Operations:
Income (loss) from discontinued operations-net of tax			(1,519	)			21,466				26,817				17,429				41,684
Gain from sale of discontinued operations-net of tax			159,961				42,753				—				—				—
Discontinued operations-net of tax			158,442				64,219				26,817				17,429				41,684
Net income (loss) before cumulative effect of change in accounting principle			86,105				14,763				8,978				3,257				53,788
Cumulative effect of change in accounting principle			—				—				—				170				—
Net income (loss)			86,105				14,763				8,978				3,427				53,788
Less: Interest of non-controlling partners in the Partnership’s net income (loss):
Interest of non-controlling partners in the Partnership’s continuing operations			(48,069	)			(55,704	)			(22,331	)			(24,881	)			(24,885	)
Interest of non-controlling partners in the Partnership’s discontinued operations			(1,137	)			15,454				19,133				11,853				29,537
Interest of non-controlling partners in the Partnership’s gain on sale of discontinued operations			119,669				30,780				—				—				—
Total interest of non-controlling partners in the Partnership’s net income (loss)			70,463				(9,470	)			(3,198	)			(13,028	)			4,652
Net income attributable to Crosstex Energy, Inc.		$	15,642			$	24,233			$	12,176			$	16,455			$	49,136
Net income per common share-basic(2)		$	0.33			$	0.52			$	0.26			$	0.39			$	1.30
Net income per common share-diluted(2)		$	0.33			$	0.51			$	0.26			$	0.39			$	1.26
Dividends per share(2)(3):
Common		$	0.09			$	1.32			$	0.91			$	0.807			$	0.563

		Crosstex Energy, Inc.
		Years Ended December 31,
		2009				2008				2007				2006				2005
		(In thousands, except per share data)
Balance Sheet Data (end of period):
Working capital surplus (deficit)		$	(41,791	)		$	(20,431	)		$	(39,330	)		$	(70,091	)		$	4,872
Property and equipment, net			1,280,197				1,528,490				1,426,546				1,107,242				668,632
Total assets			2,080,233				2,546,743				2,602,829				2,206,698				1,445,325
Long-term debt			873,702				1,263,706				1,223,118				987,130				522,650
Interest of non-controlling partners in the Partnership			587,624				522,961				489,034				391,103				264,726
Stockholders’ equity			815,910				738,390				246,366				279,413				111,247
Cash Flow Data:
Net cash flow provided by (used in (4)):
Operating activities		$	78,850			$	170,154			$	112,578			$	113,839			$	12,842
Investing activities			379,874				(186,768	)			(411,382	)			(885,825	)			(614,822	)
Financing activities			(461,980	)			22,720				296,022				769,717				592,365
Other Financial Data:
Gross margin(5)		$	311,222			$	307,786			$	259,826			$	158,356			$	60,118
Operating Data:
Pipeline throughput (MMBtu/d)			2,040,000				2,002,000				1,555,000				845,000				582,000
Natural gas processed (MMBtu/d)(6)			1,235,000				1,608,000				1,835,000				1,817,000				1,707,000
Producer services (MMBtu/d)			75,000				85,000				94,000				138,000				111,010

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in this report.

Overview

Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, processing and marketing of natural gas and NGLs through its subsidiaries. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 16,414,830 common units, representing approximately 33% of the limited partner interests in Crosstex Energy, L.P. as of December 31, 2009 (representing 25% of the limited partner interest as of January 31, 2010 after the Partnership’s issuance of Series A convertible preferred units) and (ii) 100% ownership interest in Crosstex Energy GP, L.P., the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

Our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. The Partnership is required by its partnership agreement to distribute all its cash on hand at the end of each quarter, less reserves established by its general partner in its sole discretion to provide for the proper conduct of the Partnership’s business or to provide for future distributions.

The incentive distribution rights entitle us to receive an increasing percentage of cash distributed by the Partnership as certain target distribution levels are reached. Specifically, they entitle us to receive 13.0% of all cash distributed in a quarter after each unit has received $0.25 for that quarter, 23.0% of all cash distributed after each unit has received $0.3125 for that quarter, and 48.0% of all cash distributed after each unit has received $0.375 for that quarter.

Prior to 2009, we received quarterly distributions from the Partnership with the last distribution for the fourth quarter of 2008 received in February 2009. During 2009, the Partnership’s ability to distribute available cash was contractually restricted by the terms of its credit facility due to its high leverage ratios and it ceased making distributions. Although the Partnership’s new credit facility should not limit its ability to make distributions during 2010 and in the future, any decision to resume cash distributions on its units and the amount of any such distributions would consider maintaining sufficient cash flow in excess of the distribution to continue to move the Partnership towards lower leverage ratios. The Partnership has established a target over the next couple of years of achieving a ratio of total debt to Adjusted EBITDA of less than 4.0 to 1.0, and the Partnership does not currently expect to resume cash distributions on its outstanding units until it achieves such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). The Partnership will also consider general economic conditions and its outlook for business as it determines to pay any distribution.

Since our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own, we do not expect to receive any cash flows until the Partnership is able to improve its leverage ratio and begin making distributions again. As of December 31, 2009, we have $9.9 million of cash (excluding cash held by the Partnership) which we expect to be sufficient to pay our expenses and federal income taxes and to fund our general partner contributions over the next several years based on our forecasted cash flows. We do not anticipate making any future dividend payments until we begin receiving distributions from the Partnership again.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. The interest owned by non-controlling partners’ share of income is reflected separately in our results of operations. We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Our consolidated results of operations are derived from the results of operations of the Partnership and also include our gains on the issuance of units in the Partnership, deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operation. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

Historically, the Partnership has operated two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the north Texas Barnett Shale area, and in Louisiana and Mississippi. In February 2009, the Oklahoma assets were sold; in August 2009 the Alabama, Mississippi and south Texas Midstream properties were sold; and in October 2009 the Treating assets were sold, as more fully described under “Recent Developments and Business Strategy.” The Partnership’s primary focus for continuing operations is on the gathering, processing, transmission and marketing of natural gas and NGLs, as well as providing certain producer services, which constitute one reporting segment of midstream activity. Currently, the geographic focus is in the north Texas Barnett shale area and in Louisiana. The Partnership focuses on gross margin to manage its operations because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport or market natural gas or NGLs for a fee. The Partnership buys and sells most of its natural gas at a fixed relationship to the relevant index price. In addition, the Partnership receives certain fees for processing based on a percentage of the liquids produced and enters into hedge contracts for its expected share of the liquids produced to protect margins from changes in liquids prices.

The Partnership’s margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities and the volumes of NGLs handled at its fractionation facilities. The Partnership generates revenues from four primary sources:

•

purchasing and reselling or transporting natural gas on the pipeline systems it owns;

•

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

•

providing compression services; and

•

providing off-system marketing services for producers.

The Partnership generally gathers or transports gas owned by others through its facilities for a fee, or it buys natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transports and resells the natural gas. The Partnership attempts to execute all purchases and sales substantially concurrently, or it enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. Gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. The Partnership is also party to certain long-term gas sales commitments that it satisfies through supplies purchased under long-term gas purchase agreements. When the Partnership enters into those arrangements, its sales obligations generally match its purchase obligations. However, over time the supplies that are under contract may decline due to reduced drilling or other causes and the Partnership may be required to satisfy the sales obligations by buying additional gas at prices that may exceed the prices received under the sales commitments. In the Partnership’s purchase/sale transactions, the resale price is generally based on the same index at which the gas was purchased. However, the Partnership has certain purchase/sale transactions in which the purchase price is based on a production-area index and the sales price is based on a market-area index, and it captures the difference in the indices (also referred to as basis spread), less the transportation expenses from the two areas, as its margin. Changes in the basis spread can increase or decrease margins (or even be negative at times).

The Partnership realizes margins from processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fee based. Under the margin contract arrangements the Partnership’s margins are higher during periods of high liquid prices relative to natural gas prices. Gross margin results under a POL contract are impacted only by the value of the liquids produced. Under fee based contracts the Partnership’s margins are driven by throughput volume. See “—Commodity Price Risk.”

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

Recent Developments and Business Strategy

From the Partnership’s inception in 2002 until the second half of 2008, its long-term strategy had been to increase distributable cash flow per unit by accomplishing economies of scale through new construction or expansion in core operating areas and making accretive acquisitions of assets that are essential to the production, transportation and marketing of natural gas and NGLs. In response to the volatility in the commodity and capital markets over the last 18 months and other events, including the substantial decline in commodity prices, the Partnership adjusted its business strategy in the fourth quarter 2008 and in 2009 to focus on maximizing liquidity, improving its balance sheet through debt reduction and other methods, maintaining a stable asset base, improving the profitability of its assets by increasing their utilization while controlling costs and reducing capital expenditures. Consistent with this strategy, the Partnership divested non-core assets since October 2008 for aggregate sale proceeds of $618.7 million and substantially reduced outstanding debt. It plans to continue the focus on (i) improving existing system profitability, (ii) continuing to improve the balance sheet and financial flexibility and (iii) pursuing strategic acquisitions and undertaking selective construction and expansion opportunities. The Partnership is successfully executing its plan as highlighted by the following accomplishments:

•

Sold Non-Core Assets. The Partnership sold $618.7 million of non-core assets and repaid approximately $500 million in long-term indebtedness from the sales proceeds over the last 15 months. In November 2008 the Partnership sold its 12.4% interest in the Seminole gas processing plant for $85.0 million. In the first quarter of 2009, the Partnership sold the Arkoma system for approximately $10.7 million. In August 2009, it sold the midstream assets in Alabama, Mississippi and south Texas for approximately $217.6 million. In addition, in October 2009, the Partnership sold its natural gas treating business for $265.4 million. The Partnership also sold its east Texas midstream assets on January 15, 2010 for $40.0 million.

•

Reduced Capital Expenditures. The Partnership reduced capital expenditures from over $275.6 million for 2008 to $101.4 million in 2009 and focused the capital projects spending on lower risk projects with higher expected returns.

•

Reduced Operating and General and Administrative Expenses. The Partnership reduced operating expenses from continuing operations to $110.4 million for the year ended December 31, 2009 from $125.8 million for the year December 31, 2008 and general and administrative expenses from continuing operations to $59.9 million for the year ended December 31, 2009 from $68.9 million for the year December 31, 2008 by reducing staffing and controlling costs. General and administrative expenses for the year ended December 31, 2009 also include non-recurring costs totaling $4.4 million associated with severance payments, lease termination costs and bad debt expense due to the SemStream, L.P. bankruptcy.

•

Acquired Certain Assets in Our Core Areas. The Partnership acquired the Eunice NGL processing plant and fractionation facility in October 2009 for $23.5 million in cash and the assumption of $18.1 million in debt. It originally acquired the contract rights associated with the Eunice plant as part of the south Louisiana acquisition in November 2005 and operated and managed the plant under an operating lease with an unaffiliated third party prior to the recent acquisition. This acquisition will eliminate lease obligations of $12.2 million per year. The Partnership also acquired the Intracoastal Pipeline located in southern Louisiana for approximately $10.3 million in December 2009. Both of these acquisitions were designed to enhance the NGL business.

•

Sale of Preferred Units. On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions. The 14,705,882 preferred units are convertible at any time into common units of the Partnership on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. The Partnership has the right to force conversion of the preferred units after three years if (i) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 days ending on two trading days before the date on which the notice is delivered of such conversion, and (ii) the average daily trading volume of common units must have exceeded 250,000 common units for 20 out of the trailing 30 trading days ending on two trading days before the date on which the notice is delivered of such conversion. The preferred units are not redeemable but will pay a quarterly distribution that will be the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units.

•

Issuance of Senior Unsecured Notes. On February 10, 2010, the Partnership issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes due 2018 at an issue price of 97.907% to yield 9.25% to maturity. Net proceeds from the sale of the notes of $689.7 million (net of transaction costs and original issue discount), together with borrowings under its new credit facility discussed below, were used to repay in full amounts outstanding under its existing bank credit facility and senior secured notes and to pay related fees, costs and expenses, including the settlement of interest rate swaps associated with its existing credit facility. The notes are unsecured and unconditionally guaranteed on a senior basis by certain of our direct and indirect subsidiaries, including substantially all of our current subsidiaries. Interest payments will be paid semi-annually in arrears starting in August 2010. The Partnership has the option to redeem all or a portion of the notes at any time on or after February 15, 2014, at the specified redemption prices. Prior to February 15, 2014, it may redeem the notes, in whole or in part, at a “make-whole” redemption price. In addition, the Partnership may redeem up to 35% of the notes prior to February 15, 2013 with the cash proceeds from certain equity offerings.

•

New Credit Facility. In February 2010, the Partnership amended and restated its existing secured bank credit facility with a new syndicated secured bank credit facility which will be guaranteed by substantially all of the Partnership’s subsidiaries. The size of the new credit facility is $420.0 million and matures in February 2014. Obligations under the new credit facility will be secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all of the equity interests in substantially all of the Partnership’s subsidiaries. Under the new credit facility, borrowings will bear interest at the Partnership’s option at the British Bankers Association LIBOR Rate plus an applicable margin, or the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate, in each case plus an applicable margin. It will pay a per annum fee on all letters of credit issued under the new credit facility, and will pay a commitment fee of 0.50% per annum on the unused availability under the new credit facility. The letter of credit fee and the applicable margins for its interest rate vary quarterly based on the Partnership’s leverage ratio.

Acquisitions and Expansion Prior to 2009

The Partnership grew significantly through asset purchases and construction and expansion projects in years prior to 2009. As discussed above, it disposed of certain assets during late 2008 and 2009 to refocus its business on the gathering, processing, transmission and marketing of natural gas and NGLs in the north Texas Barnett Shale area and in Louisiana. These acquisitions and dispositions create many of the major differences when comparing operating results from one period to another. The most significant asset purchase since January 2006 was the acquisition of midstream assets from Chief in June 2006. In addition, internal expansion projects in north Texas and Louisiana have contributed to the increase in business during 2006, 2007, 2008 and 2009. The Partnership also acquired treating assets during 2006 that were included in the sale of its Treating business in 2009 as discussed above.

On June 29, 2006, the Partnership expanded operations in the north Texas area through the acquisition of the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.3 million. Immediately following the closing of the Chief acquisition, it began expanding its north Texas pipeline gathering system. The continued expansion of the Partnership’s north Texas gathering systems to handle the growing production in the Barnett Shale was one of its core areas for internal growth during 2006, 2007, 2008 and 2009. Since the date of the acquisition through December 31, 2009, the Partnership has expanded its gathering system, connected in excess of 500 new wells to its north Texas gathering system and significantly increased the productive acreage dedicated to its systems. As of December 31, 2009, total capacity on its north Texas gathering system was approximately 1,100 MMcf/d and total throughput was approximately 793,000 MMBtu/d for the year ended December 31, 2009. Since 2006, the Partnership has constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including its Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, its Azle plant, which is a 50 MMcf/d cryogenic processing plant and its Goforth plant, which is a 30 MMcf/d processing plant. Total processing throughput averaged 219,000 MMBtu/d for the year ended December 31, 2009.

In 2007, the Partnership extended its Crosstex LIG system to the north to reach additional productive areas in the developing natural gas fields south of Shreveport, Louisiana, primarily in the Cotton Valley formation. This extension, referred to as the north Louisiana expansion, consists of 63 miles of 24” mainline with 9 miles of gathering lateral pipeline. The Partnership’s north Louisiana expansion bisects the developing Haynesville Shale gas play in north Louisiana. The north Louisiana expansion was operating at near capacity during 2008 as Haynesville gas was beginning to develop so the Partnership added 35 MMcf/d of capacity by adding compression during the third quarter of 2008 bringing the total capacity of the north Louisiana expansion to approximately 275 MMcf/d. The Partnership continued the expansion of its north Louisiana system during 2009 increasing capacity by 100 MMcf/d in July 2009 by adding compression. It increased capacity by another 35 MMcf/d with a new interconnect into an interstate pipeline in December 2009 and bringing total capacity to 410 MMcf/d by the end of 2009. The Partnership has long-term firm transportation agreements subscribing to all of the incremental capacity added during 2009. In addition, the Partnership added compression during 2009 between the southern portion of its Crosstex LIG system and the northern expansion of its Crosstex LIG system which increased the capacity to bring gas from the north to its markets in the south to 145 MMcf/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission, Trunkline Gas and Tennessee Gas Pipeline.

Impact of Federal Income Taxes

Crosstex Energy, Inc. is a corporation for federal income tax purposes. As such, our federal taxable income is subject to tax at a maximum rate of 35.0% under current law. We expect to have taxable income allocated to us as a result of our investment in the Partnership’s units, particularly because of remedial allocations that will be made among the unitholders. Taxable income allocated to us by the Partnership will increase over the years as the results of operation increase and as the ratio of income to distributions increases for all of the unitholders.

As of December 31, 2009 we have a net operating loss carry forward of $47.5 million for federal income taxes and state loss carry forwards of $30.1 million. We believe it is more likely than not that our future results of operations will generate sufficient taxable income to utilize these net operating loss carry forwards before they expire. Once these net operating loss carry forwards are fully utilized, we will have to pay tax on our federal taxable income at a maximum rate of 35.0% under current law.

Our use of this net operating loss carry forward will be limited if there is a greater than 50.0% change in our stock ownership over a three year period.

Commodity Price Risk

The Partnership’s business is subject to significant risks due to fluctuations in commodity prices. Its exposure to these risks is primarily in the gas processing component of its business. A large percentage of the processing fees are realized under POL contracts that are directly impacted by the market price of NGLs. It also realizes processing gross margins under margin contracts. These settlements are impacted by the relationship between NGL prices and the underlying natural gas prices, which is also referred to as the fractionation spread.

A significant volume of inlet gas at the Partnership’s south Louisiana and north Texas processing plants is settled under POL agreements. The POL fees are denominated in the form of a share of the liquids extracted and the Partnership is not responsible for the fuel or shrink associated with processing. Therefore, fee revenue under a POL agreement is directly impacted by NGL prices, and the decline of these prices in 2008 and early 2009, contributed to a significant decline in gross margin from processing. The Partnership has a number of fractionation margin contracts on its Plaquemine and Gibson processing plants that expose it to the fractionation spread. Under these margin contracts its gross margin is based upon the difference in the value of NGLs extracted from the gas less the value of the product in its gaseous state (“shrink”) and the cost of fuel to extract during processing. During the last half of 2008 and early 2009, the fractionation spread narrowed significantly as the value of NGLs decreased more than the value of the gas and fuel associated with the processed gas. Thus the gross margin realized under these margin contracts was negatively impacted due to the commodity price environment. Such a decline may negatively impact its gross margin in the future if such declines continue.

The Partnership is also subject to price risk to a lesser extent for fluctuations in natural gas prices with respect to a portion of its gathering and transportation services. Approximately 8.0% of the natural gas it markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the natural gas at a percentage of the index price, resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices.

See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for additional information on Commodity Price Risk.

Results of Operations

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

		Years Ended December 31,
		2009				2008				2007
		(Dollars in millions)
Midstream revenues		$	1,453.3			$	3,072.6			$	2,380.2
Purchased gas			(1,147.8	)			(2,768.2	)			(2,124.5	)
Gas and NGL marketing activities			5.7				3.4				4.1
Total gross margin		$	311.2			$	307.8			$	259.8
Volumes (MMBtu/d):
Gathering and transportation			2,040,000				2,002,000				1,555,000
Processing			1,235,000				1,608,000				1,835,000
Producer services			75,000				85,000				94,000

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Gross Margin and Gas and NGL Marketing Activities. Midstream gross margin was $311.2 million for the year ended December 31, 2009 compared to $307.8 million for the year ended December 31, 2008, an increase of $3.4 million, or 1.1%. The increase was primarily due to higher margins on gathering and transmission throughput volume. These increases were partially offset by gross margin declines in the processing business due to a less favorable NGL market. Gas and NGL marketing activities increased for the comparative periods by approximately $2.4 million primarily due to an improved fee structure and an increase in activity in the liquids marketing business.

The LIG gathering and transmission system contributed gross margin growth of $14.0 million for the twelve months ended December 31, 2009 over the same period in 2008 primarily due to improved pricing and higher volumes on the northern part of the system offsetting a decrease in sales volume at southern delivery points. The north Texas region contributed $13.9 million of gross margin growth for the comparative periods primarily due to increased volume on the gathering systems. The gross margin increase contributed by the north Texas region was partially offset by an increase in purchased gas costs of $3.7 million related to the arbitration award to Denbury discussed under “Contingencies.” The weaker processing environment contributed to a significant decline in the gross margins for processing plants in Louisiana for the twelve months ended December 31, 2009. Overall the plants in the region reported a margin decrease of approximately $15.1 million. The primary contributors to this decrease were the Gibson, Plaquemine and Blue Water processing plants which had gross margin declines of $9.8 million, $7.6 million and $3.5 million, respectively. These declines were partially offset by an increase of approximately $8.3 million in the fractionation and liquids marketing activities in the region. The Arkoma system, which was sold in April 2009, created a negative gross margin variance of $4.0 million when compared to the same period in 2008. The Crosstex Pipeline system in east Texas had a gross margin decline of $1.7 million primarily due to a decline in throughput volumes.

Operating Expenses. Operating expenses were $110.4 million for the year ended December 31, 2009 compared to $125.8 million for the year ended December 31, 2008, a decrease of $15.4 million, or 12.2%, resulting primarily from initiatives undertaken in late 2008 and early 2009 to reduce expenses.

General and Administrative Expenses. General and administrative expenses were $62.5 million for the year ended December 31, 2009 compared to $72.4 million for the year ended December 31, 2008, a decrease of $9.9 million, or 13.7%. The decrease is a result of strategic initiatives undertaken to reduce expenses and primarily relate to workforce reductions. The 2009 amount includes $4.4 million of non-recurring costs consisting of $3.1 million of severance payments, $0.8 million of lease termination costs and $0.5 million of bad debt expense due to the SemStream, L.P. bankruptcy.

Gain/Loss on Derivatives. Gains on derivatives were $3.0 million for the year ended December 31, 2009 compared to gains of $8.6 million for the year ended December 31, 2008. The derivative transaction types contributing to the net gain are as follows (in millions):

		Years Ended December 31,
		2009								2008
		Total				Realized				Total				Realized
(Gain)/Loss on Derivatives:
Basis swaps		$	(4.4	)		$	(2.5	)		$	(8.7	)		$	(8.8	)
Processing margin hedges			1.4				(2.2	)			(3.6	)			(3.6	)
Storage			(0.3	)			(1.1	)			(0.7	)			(0.1	)
Third-party on-system swaps			(0.1	)			(0.3	)			(0.6	)			(0.8	)
Other			0.1				—				(0.1	)			—
			(3.3	)			(6.1	)			(13.7	)			(13.3	)
Derivative gains included in income from discontinued operations			0.3				0.5				5.1				5.4
		$	(3.0	)		$	(5.6	)		$	(8.6	)		$	(7.9	)

Impairments. During the year ended December 31, 2009, the Partnership had impairment expense of $2.9 million compared to $30.2 million for the year ended December 31, 2008. During 2009, impairments totaling $2.9 million were taken on the Bear Creek processing plant and the Vermillion treating plant to bring the fair value of the plants to a marketable value for these idle assets. The impairment expense during 2008 is comprised of:

•

$17.8 million related to the Blue Water gas processing plant located in south Louisiana — The impairment on the Partnership’s 59.27% interest in the Blue Water gas processing plant was recognized because the pipeline company which owns the offshore Blue Water system and supplies gas to the Blue Water plant reversed the flow of the gas on its pipeline in early January 2009 thereby removing access to all the gas processed at the Blue Water plant from the Blue Water offshore system. As of January 2009, an alternative source of new gas for the Blue Water plant had not been found so the plant ceased operation from January 2009 until November 2009. An impairment of $17.8 million was recognized for the carrying amount of the plant in excess of its estimated fair value as of December 31, 2008.

•

$5.7 million related to goodwill — It was determined that the carrying amount of goodwill attributable to the Midstream segment was impaired because of the significant decline in Midstream operations due to negative impacts on cash flows caused by the significant declines in natural gas and NGL prices during the last half of 2008 coupled with the global economic decline.

•

$4.1 million related to leasehold improvements — The Partnership had planned to relocate its corporate headquarters during 2008 to a larger office facility. The Partnership had leased office space and was close to completing the renovation of this office space when the global economic decline began impacting operations in October 2008. On December 31, 2008, the decision was made to cancel the new office lease and not relocate the corporate offices from its existing office location. The impairment relates to the leasehold improvements on the office space for the cancelled lease.

•

$2.6 million related to the Arkoma gathering system — The impairment on the Arkoma gathering system was recognized because the asset was sold in February 2009 for $10.7 million and the carrying amount of the plant exceeded the sale price by approximately $2.6 million.

Depreciation and Amortization. Depreciation and amortization expenses were $119.2 million for the year ended December 31, 2009 compared to $107.7 million for the year ended December 31, 2008, an increase of $11.5 million, or 10.7%, resulting primarily from growth and expansion in the NTP, NTG and north Louisiana areas.

Interest Expense. Interest expense was $95.1 million for the year ended December 31, 2009 compared to $74.9 million for the year ended December 31, 2008, an increase of 20.2 million, or 27.0%. Net interest expense consists of the following (in millions):

		Years Ended December 31,
		2009				2008
Senior notes		$	28.3			$	22.5
PIK			4.9				—
Credit facility			30.7				20.8
Series B secured note			0.4				—
Capitalized interest			(1.1	)			(2.7	)
Mark to market interest rate swaps			(0.8	)			22.1
Realized interest rate swaps			19.0				4.6
Interest income			(0.2	)			(0.4	)
Amortization of debt issue cost			7.6				2.9
Other			6.3				5.1
Total		$	95.1			$	74.9

Loss on Extinguishment of Debt. The Partnership recognized a loss on extinguishment of debt during the year ended December 31, 2009 of $4.7 million due to the February 2009 amendment to the senior secured notes agreement. The modifications to this agreement pursuant to this amendment were substantive as defined in FASB ASC 470-50 and were accounted for as the extinguishment of the old debt and the creation of new debt. As a result, the unamortized costs associated with the senior secured notes prior to the amendment as well as the fees paid to the senior secured lenders for the February 2009 amendment were expensed during the year ended December 31, 2009.

Other Income. Other income was $1.4 million for the year ended December 31, 2009 compared to $27.9 million for the year ended December 31, 2008. In November 2008, the Partnership sold a contract right for firm transportation capacity on a third party pipeline to an unaffiliated third party for $20.0 million. The entire amount of such proceeds is reflected in other income because the Partnership had no basis in this contract right. In February 2008, the Partnership recorded $7.0 million from the settlement of disputed liabilities that were assumed with an acquisition.

Income Taxes. We provide for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. Income tax benefit was $6.0 million and $1.4 million for the years ended December 31, 2009 and 2008, respectively.

Gain on Issuance of Units of the Partnership. As a result of the Partnership issuing common units in April 2008 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and we recognized a gain on issuance of such units.

Discontinued Operations. The Partnership sold the following non-strategic assets over the past year and used the proceeds from such sales to repay long-term indebtedness:

Assets		Date of Sale
12.4% interest in the Seminole Gas Processing Plant		November 2008
Oklahoma assets (Arkoma system)		February 2009
Alabama, Mississippi and south Texas assets		August 2009
Treating assets		October 2009

In accordance with FASB ASC 360-10-05-4, the results of operations related to each of the assets listed above (except the Arkoma assets which were immaterial to the financial statement presentations) are presented in income from discontinued operations for the comparative periods in the statements of operations. Revenues, operating expenses, general and administrative expenses associated directly to the assets sold, depreciation and amortization, allocated Texas margin tax and allocated interest are reflected in the income from discontinued operations. During the year ended December 31, 2009, the Partnership expensed $4.3 million of unamortized debt issuance costs associated with the bank credit facility and the senior secured notes due to the repayments in borrowings of $316.3 million and $153.8 million, respectively, from proceeds of the Alabama, Mississippi and south Texas assets and Treating assets dispositions. In addition, we incurred make-whole interest and call premiums of $5.2 million in the year ended December 31, 2009 to the holders of the senior secured notes due to the call premiums on the repayments. These additional interest costs are included in discontinued operations for the year ended December 31, 2009. No corporate office general and administrative expenses have been allocated to income from discontinued operations. Following are the components of revenues and earnings from discontinued operations and operating data (dollars in millions):

		Year Ended
		December 31,
		2009				2008
Midstream revenues		$	368.1			$	1,766.1
Treating revenues		$	45.5			$	73.5
Income (loss) from discontinued operations, net of tax		$	(1.5	)		$	21.5
Gain from sale of discontinued operations, net of tax		$	160.0			$	42.8
Gathering and Transmission Volumes (MMBtu/d)			564,000				617,000
Processing Volumes (MMBtu/d)			191,000				204,000

Interest of Non-Controlling Partners in the Partnership’s Net Income (Loss) from Continuing Operations. The interest of non-controlling partners in the Partnership’s net loss was $48.1 million for the year ended December 31, 2009 compared to a net loss of $55.7 million for the year ended December 31, 2008 due to the changes shown in the following summary (in millions):

		Years Ended December 31,
		2009				2008
Net loss from continuing operations for the Partnership		$	(77.5	)		$	(63.7	)
(Income) allocation to CEI for the general partner incentive distribution			—				(30.8	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors			3.0				4.7
Loss allocation to CEI for its 2% general partner share of Partnership loss			1.5				1.2
Net loss allocable to limited partners			(73.0	)			(88.6	)
Less: CEI’s share of net (income) loss allocable to limited partners			24.9				32.6
Plus: Non-controlling partners’ share of net income in Denton County Joint Venture			—				0.3
Non-controlling partners’ share of Partnership net loss from continuing operations		$	(48.1	)		$	(55.7	)

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Gross Margin and Gas and NGL Marketing Activities. Midstream gross margin was $307.8 million for the year ended December 31, 2008 compared to $259.8 million for the year ended December 31, 2007, an increase of $48.0 million, or 18.5%. The increase was primarily due to system expansion projects and increased throughput on the Partnership’s gathering and transmission systems. These increases were partially offset by margin decreases in the processing business due to a less favorable NGL market and operating downtime resulting from the impact of hurricanes in the last half of the year. Gas and NGL marketing activities decreased for the comparative periods by approximately $0.7 million.

System expansion in the north Texas region and increased throughput on the NTP contributed $58.9 million of gross margin growth for the year ended December 31, 2008 over the same period in 2007. The Partnership’s gathering systems in the region and NTP accounted for $41.3 million and $9.1 million of this increase, respectively. The Partnership’s processing facilities in the region contributed an additional $8.5 million of gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $8.2 million during the year ended December 31, 2008 over the same period in 2007. Processing plants in Louisiana experienced a margin decline of $20.2 million for the comparative twelve-month period in 2008 due to a less favorable NGL processing environment in the last half of the year and business interruptions resulting from the impact of hurricanes along the Gulf Coast.

The Partnership’s processing and gathering systems were negatively impacted by events beyond our control during the third quarter that had a significant effect on gross margin results for the year ended December 31, 2008. Hurricanes Gustav and Ike came ashore along the Gulf coast in September 2008. The Partnership estimates that these storms resulted in approximately $22.9 million gross margin decrease for the year. The lost margin was primarily experienced at gas processing facilities along the Gulf Coast. However, processing facilities further inland in Louisiana and north Texas were indirectly impacted due to disruption in the NGL markets. In addition, approximately $0.9 million in gross margin was lost at the Sabine Pass plant in August 2008 due to downtime from fire damage. The fire occurred during an attempt to bring the plant back on line following tropical storm Edouard.

Operating Expenses. Operating expenses were $125.8 million for the year ended December 31, 2008 compared to $91.2 million for the year ended December 31, 2007, an increase of $34.5 million, or 37.8%, resulting primarily from growth and expansion in the NTP, NTG, north Louisiana and east Texas areas. The increase is primarily attributable to the following factors:

•

Contractor services and labor costs increased $12.3 million;

•

Chemicals and materials increased $6.2 million;

•

Equipment rental increased $5.8 million;

•

Ad valorem taxes increased $2.2 million; and

•

Technical services increased $0.7 million.

General and Administrative Expenses. General and administrative expenses were $72.4 million for the year ended December 31, 2008 compared to $62.3 million for the year ended December 31, 2007, an increase of $10.1 million, or 16.2%. The increase is primarily attributable to the following factors:

•

$5.5 million increase in rental expense resulting primarily from additional office rent and including $3.4 million related to lease termination fees for the cancelled relocation of our corporate headquarters;

•

$3.1 million increase in bad debt expense due to the SemStream, L.P. bankruptcy;

•

$1.8 million increase in professional fees and services; and

•

$0.9 million decrease in stock-based compensation expense resulting primarily from the reduction of estimated performance-based restricted units and restricted shares.

Gain/Loss on Derivatives. Gains on derivatives were $8.6 million for the year ended December 31, 2008 compared to gains of $4.1 million for the year ended December 31, 2007. The derivative transaction types contributing to the net gain are as follows (in millions):

		Years Ended December 31,
		2008								2007
		Total				Realized				Total				Realized
(Gain) Loss on Derivatives:
Basis swaps		$	(8.7	)		$	(8.8	)		$	(8.1	)		$	(7.0	)
Processing margin hedges			(3.6	)			(3.6	)			1.3				1.3
Storage			(0.7	)			(0.1	)			(0.5	)			(1.6	)
Third-party on-system swaps			(0.6	)			(0.8	)			(0.2	)			(0.6	)
Puts			—				—				0.8				—
Other			(0.1	)			—				0.1				—
			(13.7	)			(13.3	)			(6.6	)			(7.9	)
Derivative gains included in income from discontinued operations			5.1				5.4				2.5				2.8
		$	(8.6	)		$	(7.9	)		$	(4.1	)		$	(5.1	)

Impairments. During the year ended December 31, 2008, the Partnership had an impairment expense of $30.2 million compared to no impairment expense for the year ended December 31, 2007. The 2008 impairment expense is described under “Year Ended December 31, 2009 Compared to Year Ended December 31, 2008.”

Depreciation and Amortization. Depreciation and amortization expenses were $107.7 million for the year ended December 31, 2008 compared to $83.4 million for the year ended December 31, 2007, an increase of $24.3 million, or 29.1%. Depreciation and amortization increased $22.5 million due to the NTP, NTG and north Louisiana expansion project assets. Accelerated depreciation of the Dallas office leasehold due to the planned, but subsequently cancelled, relocation accounted for an increase between periods of $1.4 million.

Interest Expense. Interest expense was $74.9 million for the year ended December 31, 2008 compared to $47.6 million for the year ended December 31, 2007, an increase of $27.2 million, or 57.1%. The increase relates primarily to the negative impact of declining interest rates on the interest rate swaps. Net interest expense consists of the following (in millions):

		Years Ended December 31,
		2008				2007
Senior notes		$	22.5			$	23.0
Credit facility			20.8				24.8
Capitalized interest			(2.7	)			(4.8	)
Mark to market interest rate swaps			22.1				1.2
Realized interest rate swaps			4.6				(0.7	)
Interest income			(0.4	)			(1.2	)
Amortization of debt issue cost			2.9				2.6
Other			5.1				2.7
Total		$	74.9			$	47.6

Other Income. Other income was $27.9 million for the year ended December 31, 2008 compared to $0.5 million for the year ended December 31, 2007. In November 2008, the Partnership sold a contract right for firm transportation capacity on a third party pipeline to an unaffiliated third party for $20.0 million. In February 2008, the Partnership recorded $7.0 million from the settlement of disputed liabilities that were assumed with an acquisition.

Income Taxes. We provide for income taxes using the liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book basis of assets and liabilities that will reverse in future periods. We had an income tax benefit of $1.4 million in the year ended December 31, 2008. Income tax benefit of $1.4 million and income tax expense of $6.3 million was recorded for the years ended December 31, 2008 and 2007, respectively.

Gain on Issuance of Units of the Partnership. As a result of the Partnership issuing common units in April 2008 and December 2007 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and $7.5 million, respectively, and we recognized a gain on issuance of such units.

Discontinued Operations. Income from discontinued operations were $64.2 million for the year ended December 31, 2008 compared to $26.8 million for the year ended December 31, 2007. Discontinued operations includes income related to the Seminole gas processing plant disposed of in November 2008, income related to the Alabama, Mississippi and south Texas assets disposed of in August 2009 and income related to the Treating assets disposed of in October 2009. The reported income for the comparative periods has been recast to include 2009 dispositions in income from discontinued operations.

Interest of Non-Controlling Partners in the Partnership’s Net Income (Loss) from Continuing Operations. The interest of non-controlling partners in the Partnership’s net loss was $55.7 million for the year ended December 31, 2008 compared to a net loss of $22.3 million for the year ended December 31, 2007 due to the changes shown in the following summary (in millions):

		Years Ended December 31,
		2008				2007
Net loss from continuing operations for the Partnership		$	(63.7	)		$	(17.3	)
(Income) allocation to CEI for the general partner incentive distribution			(30.8	)			(24.8	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors			4.7				5.4
Loss allocation to CEI for its 2% general partner share of Partnership loss			1.2				0.7
Net loss allocable to limited partners			(88.6	)			(36.0	)
Less: CEI’s share of net (income) loss allocable to limited partners			32.6				13.5
Plus: Non-controlling partners’ share of net income in Denton County Joint Venture			0.3				0.2
Non-controlling partners’ share of Partnership net loss from continuing operations		$	(55.7	)		$	(22.3	)

Critical Accounting Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment to the specific set of circumstances existing in our business. Compliance with the rules necessarily involves reducing a number of very subjective judgments to a quantifiable accounting entry or valuation. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies are discussed below. See Note 2 of the Notes to Consolidated Financial Statements for further details on our accounting policies and a discussion of new accounting pronouncements.

Revenue Recognition and Commodity Risk Management. 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. It generally accrues one month 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 utilizes extensive estimation procedures to determine the sales and cost of gas purchase accruals for each accounting cycle. Accruals are based on estimates of volumes flowing each month from a variety of sources. It uses actual measurement data, if it is available, and will use such data as producer/shipper nominations, prior month average daily flows, estimated flow for new production and estimated end-user requirements (all adjusted for the estimated impact of weather patterns) when actual measurement data is not available. Throughout the month or two following production, actual measured sales and transportation volumes are received and invoiced and used in a process referred to as “actualization”. Through the actualization process, any estimation differences recorded through the accrual are reflected in the subsequent month’s accounting cycle when the accrual is reversed and actual amounts are recorded. Actual volumes purchased, processed or sold may differ from the estimates due to a variety of factors including, but not limited to: actual wellhead production or customer requirements being higher or lower than the amount nominated at the beginning of the month; liquids recoveries being higher or lower than estimated because gas processed through the plants was richer or leaner than estimated; the estimated impact of weather patterns being different from the actual impact on sales and purchases; and pipeline maintenance or allocation causing actual deliveries of gas to be different than estimated. The Partnership believes that its accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

The Partnership engages in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and natural gas liquids. The Partnership manages its price risk related to future physical purchase or sale commitments by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance its future commitments and significantly reduce its risk to the movement in natural gas prices.

The Partnership uses derivatives to hedge against changes in cash flows related to product prices and interest rate risk, as opposed to their use for trading purposes. FASB ASC 815, requires that all derivatives and hedging instruments are recognized as assets or liabilities at fair value. If a derivative qualifies for hedge accounting, changes in the fair value can be offset against the change in the fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.

The Partnership conducts “off-system” gas marketing operations as a service to producers on systems that it does not own. The Partnership refers to these activities as part of 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 revenue and cost of sales for these activities are shown net in the statement of operations.

The Partnership manages its price risk related to future physical purchase or sale commitments for energy trading activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce risk related 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 it uses mark-to-market accounting for both physical and financial contracts of the energy trading business. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to energy trading activities are recognized in earnings as gain or loss on derivatives immediately.

Sales of Securities by Subsidiaries. We recognize gains and losses in the consolidated statements of operations resulting from subsidiary sales of additional equity interest, including the Partnership’s limited partnership units, to unrelated parties.

Impairment of Long-Lived Assets. In accordance with FASB ASC 360-10-05, the Partnership evaluates the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value.

When determining whether impairment of one of the Partnership’s long-lived assets has occurred, it must estimate the undiscounted cash flows attributable to the asset. The 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, including but not limited to:

•

changes in general economic conditions in regions in which our markets are located;

•

the availability and prices of natural gas supply;

•

the Partnership’s ability to negotiate favorable sales agreements;

•

the risks that natural gas exploration and production activities will not occur or be successful;

•

the Partnership’s dependence on certain significant customers, producers, and transporters of natural gas; and

•

competition from other midstream companies, including major energy producers.

Any significant variance in any of the above assumptions or factors could materially affect the Partnership’s cash flows, which could require us to record an impairment of an asset.

Depreciation Expense and Cost Capitalization. Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipelines owned by the Partnership. The Partnership capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed assets through the recording of depreciation expense. The Partnership capitalizes the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

The Partnership generally computes depreciation using the straight-line method over the estimated useful life of the assets. Certain assets such as land, NGL line pack and natural gas line pack are non-depreciable. The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates may be reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values, which would impact future depreciation expense.

Liquidity and Capital Resources

Cash flow presented in liquidity discussions includes cash flow from discontinued operations.

Cash Flows from Operating Activities. Net cash provided by operating activities was $78.9 million, $170.2 million and $112.6 million for the years ended December 31, 2009, 2008 and 2007, respectively. Income before non-cash income and expenses and changes in working capital for 2009, 2008 and 2007 were as follows (in millions):

		Years Ended December 31,
		2009				2008				2007
Income before non-cash income and expenses		$	87.3			$	157.6			$	136.4
Changes in working capital			(8.4	)			12.5				(23.9	)

The primary reason for the decreased cash flow from income before non-cash income and expenses of $70.3 million from 2008 to 2009 was increased interest expense of $19.4 million, decreased operating income of $11.2 million, decreased other income of $26.8 million, and decreased gain on derivatives of $7.2 million. The primary reason for the increased cash flow from income before non-cash income and expenses of $21.2 million from 2007 to 2008 was increased operating income from the Partnership’s expansion in north Texas and north Louisiana during 2007 and 2008.

Cash Flows from Investing Activities. Net cash provided in investing activities was $379.9 million for the year ended December 31, 2009 primarily due to proceeds from asset sales. Net cash used in investing activities was $186.8 million and $411.4 million for the years ended December 31, 2008 and 2007, respectively. Cash flows from investing activities for the years ended December 31, 2009, 2008 and 2007 include proceeds from property sales of $503.9 million, $88.8 million and $3.1 million, respectively. Sales in 2009 primarily relate to the sale of the Partnership’s Alabama, Mississippi, south Texas and Treating assets. Sales in 2008 relate to the sale of the Partnership’s interest in the Seminole gas processing plant. The 2007 sales primarily relate to sales in inactive properties. Our primary investing activities for 2009, 2008 and 2007 were capital expenditures and acquisitions in the Partnership, net of accrued amounts, as follows (in millions):

		Years Ended December 31,
		2009				2008				2007
Growth capital expenditures		$	90.5			$	257.2			$	403.7
Acquisitions and asset purchases			35.1				—				—
Maintenance capital expenditures			10.9				18.3				10.8
Total		$	136.5			$	275.5			$	414.5

Net cash invested in Midstream assets was $123.8 million, $222.4 million and $385.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. Net cash invested in Treating assets was $11.1 million, $41.8 million and $23.5 million for the years ended December 31, 2009, 2008 and 2007 respectively. Net cash invested in other corporate assets was $1.6 million, $11.4 million and $5.2 million for the years ended December 31, 2009, 2008 and 2007 respectively.

Cash Flows from Financing Activities. The Partnership disposed of non-core assets and repaid outstanding debt which resulted in net cash used by financing activities of $462.0 million for the year ended December 31, 2009. Net cash provided in financing activities was $22.7 million and $296.0 million for the years ended December 31, 2008 and 2007, respectively. Our financing activities primarily relate to funding of capital expenditures and acquisitions in the Partnership. Our financings have primarily consisted of borrowings and repayments under the Partnership’s bank credit facility, payments on senior secured notes, borrowings under capital lease obligations, equity offerings and senior note issuances in the Partnership in 2009, 2008 and 2007 as follows (in millions):

		Years Ended December 31,
		2009				2008				2007
Net borrowings under bank credit facility (1)		$	(254.4	)		$	50.0			$	246.0
Senior secured note issuances (net of repayments) (2)			(163.2	)			(9.4	)			(9.4	)
Common unit offerings			—				101.9				58.8
Net borrowings (payments) under capital lease obligations			(0.7	)			23.9				3.6
Debt refinancing costs			(15.0	)			(4.9	)			(0.9	)
Senior subordinated unit offerings			—				—				102.6

Dividends to shareholders and distributions to non-controlling partners in the Partnership represent our primary use of cash in financing activities. Total cash distributions made during the last three years were as follows (in millions):

		Years Ended December 31,
		2009				2008				2007
Dividends to shareholders		$	4.2			$	62.0			$	42.6
Non-controlling partners			7.6				63.2				39.0
Total		$	11.8			$	125.2			$	81.6

In order to reduce our interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility. Changes in drafts payable for 2009, 2008 and 2007 were as follows (in millions):

		Years Ended December 31,
		2009				2008				2007
Decrease in drafts payable		$	(16.3	)		$	(7.4	)		$	(19.0	)

Working Capital Deficit. We had a working capital deficit of $41.8 million as of December 31, 2009, primarily due to a net liability for the fair value of derivatives of $21.3 million and the current portion of long-term debt of $28.6 million related to the senior secured notes. The fair value of derivatives reflects the mark-to-market of such derivatives including a net current liability of $18.0 million related to interest rate swaps and a net current liability of $3.3 million related to commodity derivatives. In February 2010, the senior secured notes were repaid in full and the interest rate swaps were settled. Changes in working capital may fluctuate significantly between periods even though the Partnership’s trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of its revenues are collected and a large volume of its gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although the Partnership strives to minimize natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period to period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includes mark to market derivative assets and liabilities associated with commodity derivatives which may fluctuate significantly due the changes in natural gas and NGL prices and associated with interest rate swap derivatives which may fluctuate significantly due to changes in interest rates. The changes in working capital during the years ended December 31, 2009, 2008 and 2007 are due to the impact of the fluctuations discussed above.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of December 31, 2009 and 2008.

January 2010 Sale of Preferred Units. On January 19, 2010, the Partnership issued approximately $125.0 million of Series A Convertible Preferred Units to an affiliate of Blackstone/GSO Capital Solutions. The 14,705,882 preferred units are convertible at any time into Partnership common units on a one-for-one basis, subject to certain adjustments in the event of certain dilutive issuances of common units. The Partnership has the right to force conversion of the preferred units after three years if (i) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 days ending on two trading days before the date on which the Partnership delivers notice of such conversion, and (ii) the average daily trading volume of common units must have exceeded 250,000 common units for 20 out of the trailing 30 trading days ending on two trading days before the date on which the Partnership delivers notice of such conversion. The preferred units are not redeemable but will pay a quarterly distribution that will be the greater of $0.2125 per unit or the amount of the quarterly distribution per unit paid to common unitholders, subject to certain adjustments. Such quarterly distribution may be paid in cash, in additional preferred units issued in kind or any combination thereof, provided that the distribution may not be paid in additional preferred units if the Partnership pays a cash distribution on common units.

April 2008 Sale of Common Units. On April 9, 2008, the Partnership issued 3,333,334 common units in a private offering at $30.00 per unit, which represented an approximate 7% discount from the market price on such date. Net proceeds from the issuance, including our general partner contribution less expenses associated with the issuance, were approximately $102.0 million.

December 2007 Sale of Common Units. On December 19, 2007, the Partnership issued 1,800,000 common units at a price of $33.28 per unit for net proceeds of $57.6 million. We made a general partner contribution of $1.2 million in connection with the issuance to maintain our 2% general partner interest.

March 2007 Sale of Senior Subordinated Series D Units. On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests in a private offering for net proceeds of approximately $99.9 million. The senior subordinated series D units were issued at $25.80 per unit, which represented a discount of approximately 25% to the market value of common units on such date. The discount represented an underwriting discount plus the fact that the units would not receive a distribution nor be readily transferable for two years. We made a general partner contribution of $2.7 million in connection with this issuance to maintain our 2% general partner interest. The senior subordinated series D units automatically converted into common units on March 23, 2009 at a ratio of 1.05 common unit for a total issuance of 4,069,106 common units. The senior subordinated series D units were not entitled to distributions of available cash or allocations of net income/loss from the Partnership until March 23, 2009.

Capital Requirements of the Partnership. The Partnership reduced its capital expenditures for 2009 to improve liquidity. Total capital expenditures in the calendar year 2009 were less than $101.4 million. The Partnership utilized cash flow from operations and existing capacity under its bank credit facility to fund such expenditures. The Partnership’s 2010 capital budget includes approximately $25.0 million of identified growth projects, and it expects to fund such expenditures with internally generated cash flow, with any excess cash flow applied toward debt, working capital or new projects. Although the Partnership expects to identify more growth projects during 2010 in addition to projects currently budgeted, it does not anticipate that its capital expenditures during 2010 will exceed $100.0 million.

Total Contractual Cash Obligations: A summary of the Partnership’s total contractual cash obligations as of December 31, 2009 is as follows (in millions):

		Payments Due by Period
		Total				2010				2011				2012				2013				2014				Thereafter
Long-Term Debt		$	873.7			$	28.6			$	578.2			$	93.0			$	83.6			$	67.4			$	22.9
Interest Payable on Fixed Long-Term Debt Obligations			101.8				30.9				27.2				22.0				13.9				6.4				1.4
PIK Interest payable			19.0				—				19.0				—				—				—				—
Capital Lease Obligations			27.9				3.1				3.0				3.0				3.0				3.0				12.8
Operating Leases			56.6				15.9				12.1				9.3				6.2				4.7				8.4
Uncertain Tax Position Obligations			3.1				3.1				—				—				—				—				—
Total Contractual Obligations		$	1,082.1			$	81.6			$	639.5			$	127.3			$	106.7			$	81.5			$	45.5

The above table does not include any physical or financial contract purchase commitments for natural gas due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

The contractual obligations reflected above have been presented without adjustment for changes in obligations due to the February 2010 repayment in full of obligations associated with our existing credit facility and senior secured notes with proceeds from the new credit facility and the new senior unsecured notes.

Description of Indebtedness

As of December 31, 2009 and 2008, long-term debt consisted of the following (in millions):

		2009				2008
Bank credit facility, interest based on Prime or LIBOR plus an applicable margin, interest rates at December 31, 2009 and 2008 were 6.75% and 3.9%, respectively		$	529.6			$	784.0
Senior secured notes (including PIK notes as defined below of $9.5 million), weighted average interest rates at December 31, 2009 and 2008 of 10.5% and 8.0%, respectively			326.0				479.7
Series B secured note assumed in the Eunice transaction, which bears interest at the rate of 9.5%			18.1				—
			873.7				1,263.7
Less current portion			(28.6	)			(9.4	)
Debt classified as long-term		$	845.1			$	1,254.3

The balance of the bank credit facility and senior secured notes was paid in full on February 10, 2010 with the proceeds from the new credit facility and the senior unsecured notes.

Credit Facility. As of December 31, 2009, the Partnership had a bank credit facility with a borrowing capacity of $859.9 million that matures in June 2011. As of December 31, 2009, $683.0 million was outstanding under the bank credit facility, including $153.4 million of letters of credit, leaving approximately $176.9 million available for future borrowing.

New Credit Facility. In February 2010, the Partnership amended and restated its existing secured bank credit facility with a new syndicated secured bank credit facility. The new credit facility has a borrowing capacity of $420.0 million and matures in February 2014. Net proceeds from the new credit facility along with net proceeds from the senior unsecured notes were used to, among other things, repay the bank credit facility and the senior secured notes.

The new credit facility will be guaranteed by substantially all of the Partnership’s subsidiaries. Obligations under the new credit facility will be secured by first priority liens on substantially all of the Partnership’s assets and those of the guarantors, including all 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.

The Partnership may prepay all loans under the new credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements. The new credit facility will require mandatory prepayments of amounts outstanding thereunder with the net proceeds of certain asset sales, extraordinary receipts, equity issuances and debt incurrences, but these mandatory prepayments will not require any reduction of the lenders’ commitments under the new credit facility.

Under the new credit facility, borrowings will bear interest at our option at the Eurodollar Rate (the British Bankers Association LIBOR Rate) plus an applicable margin or the Base Rate (the highest of the Federal Funds Rate plus 0.50%, the 30-day Eurodollar Rate plus 1.0%, or the administrative agent’s prime rate) plus an applicable margin. The Partnership will pay a per annum fee on all letters of credit issued under the new credit facility, and a commitment fee of 0.50% per annum on the unused availability under the new credit facility. The letter of credit fee and the applicable margins for its interest rate will vary quarterly based on the leverage ratio (as defined in the new credit facility, being generally computed as the ratio of total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and will be as follows:

						Eurodollar Rate				Letter of Credit
Leverage Ratio		Base Rate Loans				Loans				Fees
Greater than or equal to 5.00 to 1.00			3.25	%			4.25	%			4.25	%
Greater than or equal to 4.50 to 1.00 and less than 5.00 to 1.00			3.00	%			4.00	%			4.00	%
Greater than or equal to 4.00 to 1.00 and less than 4.50 to 1.00			2.75	%			3.75	%			3.75	%
Greater than or equal to 3.50 to 1.00 and less than 4.00 to 1.00			2.50	%			3.50	%			3.50	%
Less than 3.50 to 1.00			2.25	%			3.25	%			3.25	%

Based on the forecasted leverage ratio for 2010, the Partnership expects the applicable margin for the interest rate and letter of credit fee to be at the higher end of these ranges. The new credit facility will not have a floor for the Base Rate or the Eurodollar Rate.

The new credit facility includes financial covenants that will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter (except for the interest coverage ratio, which builds to a four-quarter test during 2010).

The maximum permitted leverage ratio will be as follows:

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5.75 to 1.00 for the fiscal quarters ending March 31, 2010 and June 30, 2010;

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5.50 to 1.00 for the fiscal quarter ending September 30, 2010;

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5.25 to 1.00 for the fiscal quarter ending December 31, 2010;

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5.00 to 1.00 for the fiscal quarter ending March 31, 2011;

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4.75 to 1.00 for the fiscal quarter ending June 30, 2011; and

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4.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

The maximum permitted senior leverage ratio (as defined in the new credit facility, but generally computed as the ratio of total secured funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges), will be 2.50 to 1.00.

The minimum consolidated interest coverage ratio (as defined in the new credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) will be as follows:

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1.50 to 1.00 for the fiscal quarter ending March 31, 2010;

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1.75 to 1.00 for the fiscal quarters ending June 30, 2010 through December 31, 2010;

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2.00 to 1.00 for the fiscal quarter ending March 31, 2011;

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2.25 to 1.00 for the fiscal quarter ending June 30, 2011; and

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2.50 to 1.00 for the fiscal quarter ending September 30, 2011 and each fiscal quarter thereafter.

In addition, the new credit facility will contain various covenants that, among other restrictions, will limit the Partnership’s ability to:

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grant or assume liens;

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make investments;

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incur or assume indebtedness;

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engage in mergers or acquisitions;

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sell, transfer, assign or convey assets,

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repurchase its equity, make distributions and certain other restricted payments;

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change the nature of its business;

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engage in transactions with affiliates.

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enter into certain burdensome agreements;

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make certain amendments to the omnibus agreement or its subsidiaries’ organizational documents;

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prepay the senior unsecured notes and certain other indebtedness; and

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enter into certain hedging contracts.

The new credit facility will permit the Partnership to make quarterly distributions to unitholders so long as no default exists under the new credit facility.

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

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failure to pay any principal, interest, fees, expenses or other amounts when due;

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failure to meet the quarterly financial covenants;

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failure to observe any other agreement, obligation, or covenant in the new credit facility or any related loan document, subject to cure periods for certain failures;

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the failure of any representation or warranty to be materially true and correct when made;

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the Partnership or any of its subsidiaries’ default under other indebtedness that exceeds a threshold amount;

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judgments against the Partnership or any of its material subsidiaries, in excess of a threshold amount;

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certain ERISA events involving the Partnership or any of its material subsidiaries, in excess of a threshold amount;

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bankruptcy or other insolvency events involving the Partnership or any of its material subsidiaries; and

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a change in control (as defined in the new credit facility).

If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under the new credit facility will immediately become due and payable. If any other event of default exists under the new credit facility, the lenders may accelerate the maturity of the obligations outstanding under the new credit facility and exercise other rights and remedies. In addition, if any event of default exists under the new credit facility, the lenders may commence foreclosure or other actions against the collateral.

If any default occurs under the new credit facility, or if the Partnership is unable to make any of the representations and warranties in the new credit facility, the Partnership will be unable to borrow funds or have letters of credit issued under the new credit facility.

The Partnership will be subject to interest rate risk on the new credit facility and may enter into interest rate swaps to reduce this risk.

The Partnership expects to be in compliance with the covenants in the new credit facility for the next twelve months.

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
June 2003		$	1,607				9.45	%
July 2003			1,000				9.38	%
June 2004			50,629				9.46	%
November 2005			57,380				8.73	%
March 2006			40,504				8.82	%
July 2006			165,390				9.46	%
Total Outstanding			316,510
PIK Notes Payable (1)			9,524
Balance as of December 31, 2009 (2)		$	326,034