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

OR

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

For the transition period from                      to                     

Commission file number: 000-50067

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None.

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 Securities 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 Common Units representing limited partner interests held by non-affiliates of the registrant was approximately $70,576,421 on June 30, 2009, based on $3.11 per unit, the closing price of the Common Units as reported on the NASDAQ Global Select Market on such date.

At February 16, 2010, there were 49,691,715 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
None.

 

 

TABLE OF CONTENTS

DESCRIPTION

Item		Page
PART I
1. BUSINESS			3
1A. RISK FACTORS			15
1B. UNRESOLVED STAFF COMMENTS			30
2. PROPERTIES			30
3. LEGAL PROCEEDINGS			30
4. RESERVED			31
PART II
5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			31
6. SELECTED FINANCIAL DATA			33
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			34
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			54
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			56
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			56
9A. CONTROLS AND PROCEDURES			57
9B. OTHER INFORMATION			57
PART III
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			57
11. EXECUTIVE COMPENSATION			62
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS			78
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE			80
14. PRINCIPAL ACCOUNTING FEES AND SERVICES			81
PART IV
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			82
Exhibit 10.6
Exhibit 10.9
Exhibit 12.1
Exhibit 21.1
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1

CROSSTEX ENERGY, L.P.

Our Operations

We focus on the gathering, processing, transmission and marketing of natural gas and NGLs. Our assets are located in two primary regions: north Texas and Louisiana. Our combined midstream assets consist of over 3,300 miles of natural gas gathering and transmission pipelines, nine natural gas processing plants and three fractionators. Our 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. Our transmission pipelines primarily receive natural gas from our gathering systems and from third party gathering and transmission systems and deliver natural gas to industrial end-users, utilities and other pipelines. Our processing plants remove NGLs from a natural gas stream and our fractionators separate the NGLs into separate NGL products, including ethane, propane, iso- and normal butanes and natural gasoline.

Our assets include the following:

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North Texas Assets. Our North Texas Assets are comprised of gathering, processing and transmission assets serving producers active in the Barnett Shale. Our 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 was approximately 793,000 MMBtu/d for the year ended December 31, 2009. Our 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. Our transmission asset consists 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, our Plaquemine and Gibson plants, 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. Our 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.

Our Business Strategy

From our inception in 2002 until the second half of 2008, our 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, we adjusted our business strategy in the fourth quarter 2008 and in 2009 to focus on maximizing our liquidity, improving our balance sheet through debt reduction and other methods, maintaining a stable asset base, improving the profitability of our assets by increasing their utilization while controlling costs and reducing our capital expenditures. Consistent with this strategy, we divested non-core assets since October 2008 for aggregate sale proceeds of $618.7 million and substantially reduced our outstanding debt. During 2010 we plan to continue our focus on (i) improving existing system profitability, (ii) continuing to improve our balance sheet and financial flexibility and (iii) pursuing strategic acquisitions and undertaking selective construction and expansion opportunities. Key elements of our strategy will include the following:

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Improve existing system profitability. We intend to operate our existing asset base to enhance profitability by continuing our initiatives to maximize utilization by improving operations, reducing operating costs and renegotiating contracts, when appropriate, to improve our economics. We have 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. We market 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 our systems’ capacities. As part of this process, we focus on providing a full range of services to producers and end users, including supply aggregation and transportation and hedging, which we believe provides us with a competitive advantage when we compete for sources of natural gas supply.

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Continue to improve our balance sheet and financial flexibility. We intend to continue to improve our balance sheet and financial flexibility. We have 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 we do not currently expect to resume cash distributions on our outstanding units until we achieve 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 our 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. We will also consider general economic conditions and our outlook for our business as we determine to pay any distribution. Our 2010 capital expenditure budget includes approximately $25.0 million of identified growth projects, and we expect to fund such expenditures with internally generated cash flow, with any excess cash flow applied towards debt, working capital or new projects. We will also consider the use of alternative financing strategies such as entering into joint venture arrangements. As of February 12, 2010, after our repayment of existing debt and borrowings under new debt agreements in January and early February 2010 discussed under “Recent Developments,” we have approximately $193.1 million of available capacity for additional borrowings and potential letters of credit under our new credit facility. We believe that availability under our new credit facility, our ability to issue additional partnership units and enter into strategic joint venture arrangements should provide us with the financial flexibility to facilitate the execution of our business strategy.

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

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We intend to use our 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. We pursue acquisitions that we believe will add to existing core areas in order to capitalize on our existing infrastructure, personnel and producer and consumer relationships. We also examine 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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We also intend to leverage our existing infrastructure and producer and customer relationships by expanding existing systems to meet new or increased demand for our gathering, transmission, processing and marketing services. Substantially all of our capital projects during 2009 and our planned projects for 2010 target these types of opportunities.

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We 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. We believe our existing infrastructure and construction experience provide us with a competitive advantage for such expansion opportunities. For example:

•

We established a new core area through the acquisition of LIG Pipeline Company and subsidiaries, which we 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 we 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. We then 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, we 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 our NTP, and other operations in the Barnett Shale area. Immediately prior to the acquisition, we had completed construction on our NTP. Since our 2006 acquisition, we have expanded our gathering system in north Texas and connected in excess of 500 new wells and significantly increased acreage dedicated to our systems. We have also constructed three gas processing plants with total processing capacity in the Barnett Shale of 280 MMcf/d.

•

In 2005, we 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, we 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, we acquired the Intracoastal Pipeline, which we were using under a lease arrangement and which is integrated with our NGL system in south Louisiana. Not only will the acquisition of the Intracoastal Pipeline eliminate lease expense, but at the time of the acquisition we also received additional dedications of liquids volumes into our systems from another operator in the area.

Recent Developments

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

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Sold Non-Core Assets. We 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, we sold our 12.4% interest in the Seminole gas processing plant for $85.0 million. In the first quarter of 2009, we sold our Arkoma system for approximately $10.7 million. In August 2009, we sold our midstream assets in Alabama, Mississippi and south Texas for approximately $217.6 million. In addition, in October 2009, we sold our natural gas treating business for $265.4 million. We also sold our east Texas midstream assets on January 15, 2010 for $40.0 million.

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

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Reduced Operating and General and Administrative Expenses . We reduced our 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 our 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. We 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. We 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. We 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 our NGL business.

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Sale of Preferred Units. On January 19, 2010, we 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. We have 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 we pay a cash distribution on common units.

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Issuance of Senior Unsecured Notes . On February 10, 2010, we issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes (the “notes” or “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 our new credit facility discussed below, were used to repay in full amounts outstanding under our 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 our 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. We have 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, we may redeem the notes, in whole or in part, at a “make-whole” redemption price. In addition, we 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, we amended and restated our 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 our 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 our 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 our equity interests in substantially all of our subsidiaries. Under the new credit facility, borrowings will bear interest at our 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. We will pay a per annum fee on all letters of credit issued under the new credit facility, and we 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 our interest rate vary quarterly based on our leverage ratio.

Our Assets

North Texas Assets. Our 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, we expanded the capacity on the NTP 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 our customers access to mid-west and east coast markets.

On June 29, 2006, we 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 our 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, we began expanding our north Texas gathering system.

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Gathering System. Since the date of the acquisition through December 31, 2009, we have expanded our gathering system and connected in excess of 500 new wells to our north Texas gathering system and significantly increased the productive acreage dedicated to the system. As of December 31, 2009, total capacity on our 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, we have constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including our Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, our Azle plant, which is a 50 MMcf/d cryogenic processing plant and our 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.

We have budgeted approximately $15.0 million for continued development of our 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 our gathering systems in north Texas.

Louisiana Assets. Our Louisiana assets include our Crosstex LIG intrastate pipeline system and our gas processing and liquids business in south Louisiana, referred to as our 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, our 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, we extended our 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. Our 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 we 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. We continued the expansion of our north Louisiana system during 2009 increasing capacity by 100 MMcf/d in July 2009 by adding compression. We increased our 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. We have long-term firm transportation agreements subscribing to all of the incremental capacity added during 2009. In addition, we added compression during 2009 between the southern portion of our Crosstex LIG system and the northern expansion of our Crosstex LIG system, which increased the capacity to move gas from the north LIG system to our 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.

We have 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 we completed a number of operational changes at our Eunice facility and other plants to idle certain equipment, reduce operating expenses and reconfigure operations to manage the lower utilization. In addition, we have increased our focus on upstream markets and opportunities through integration of our Crosstex LIG system and south Louisiana processing assets to improve our overall performance. In 2008, our south Louisiana assets were negatively impacted by hurricanes Gustav and Ike, which came ashore in September 2008. Although we did not sustain substantial physical damage, several offshore platforms and pipelines owned by third parties transporting gas production to our Pelican, Eunice, Sabine Pass and Blue Water processing plants were damaged by the storms. Substantially all of the production from the pipeline systems supplying our 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 our Cajun Sibon pipeline system to our 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. We 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, we 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. We 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 we became the operator of the plant. The plant has a net capacity to our 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 our 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 we process the reverse stream, we earn 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, we 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 our Pelican processing plant to the Cajun Sibon pipeline system and accesses other third party processing plants in the region. Prior to our acquisition, we utilized portions of the Intracoastal Pipeline under a long-term lease arrangement. This acquisition eliminates approximately $1.3 million of annual lease expense. We have also entered into an agreement to use the system to bring additional liquids into our 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 we purchase natural gas, we establish a margin normally by selling natural gas for physical delivery to third-party users. We can also use over-the-counter derivative instruments or enter into a future delivery obligation under futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our 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. We face strong competition in obtaining natural gas supplies and in the marketing and transportation of natural gas and NGLs. Our 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 our competitors offer more services or have greater financial resources and access to larger natural gas supplies than we do. Our competition differs in different geographic areas.

In marketing natural gas and NGLs, we have 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 our marketing operations.

We face 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 our competitors have greater financial resources or lower capital costs, or are willing to accept lower returns or greater risks. Our competition differs by region and by the nature of the business or the project involved.

Natural Gas Supply

Our transmission pipelines have connections with major interstate and intrastate pipelines, which we believe have ample supplies of natural gas in excess of the volumes required for these systems. In connection with the construction and acquisition of our gathering systems, we evaluate 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 our investment. Based on these facts, we believe that there should be adequate natural gas supply to recoup our investment with an adequate rate of return. We do not routinely obtain independent evaluations of reserves dedicated to our systems due to the cost and relatively limited benefit of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such producing reserves.

Credit Risk and Significant Customers

We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of gas exposes us 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 our overall profitability.

During the year ended December 31, 2009, we had one customer that accounted for approximately 12.2% of our 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 our results of operations.

Regulation

Regulation by FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or FERC, does not directly regulate our operations under the National Gas Act, or NGA. However, FERC’s regulation of interstate natural gas pipelines influences certain aspects of our business and the market for our 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:

•

the certification and construction of new facilities;

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the extension or abandonment of services and facilities;

•

the maintenance of accounts and records;

•

the acquisition and disposition of facilities;

•

maximum rates payable for certain services; and

•

the initiation and discontinuation of services.

While we do not own any interstate pipelines, we do transport gas in interstate commerce. The rates, terms and conditions of service under which we transport natural gas in our pipeline systems in interstate commerce are 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 our 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. Our 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. We own a number of natural gas pipelines that we believe 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.

We are 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 we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our 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. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing operations but we do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Environmental Matters

General. Our 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 our overall costs of doing business, including costs of planning, constructing, and operating plants, pipelines, and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade equipment and facilities. Similar costs are likely upon changes in laws or regulations and upon any future acquisition of operating assets.

Any failure to comply with applicable environmental laws and regulations, including those relating to equipment failures and 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 we currently hold all material governmental approvals required to operate our major facilities. As part of the regular overall evaluation of our operations, we have implemented procedures to review and update governmental approvals as necessary. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations currently in effect will not have a material adverse effect on our 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 our possible future operations, and we cannot assure you that we 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, we may be unable to pass on those cost increases to our customers. A discharge of hazardous substances or wastes into the environment could, to the extent losses related to the event are not insured, subject us 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 natural resources or property. We 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 with respect to more stringent future laws and regulations of more rigorous enforcement of existing laws and regulations.

Hazardous Substance and Waste. To a large extent, the environmental laws and regulations affecting our 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 ordinary operations, we may generate wastes that may fall within the definition of a “hazardous substance.” In addition, there are other laws and regulations that can create liability for releases of petroleum, natural gas or NGLs. Moreover, we 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. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or any analogous federal or state laws.

We also generate, 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/or comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. From time to time, the Environmental Protection Agency, or EPA, and state regulatory agencies have 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 us 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 laws or regulations may result in an increase in our capital expenditures or plant operating expenses or otherwise impose limits or restrictions on our production and operations.

We currently own or lease, and have in the past owned or leased, and in the future we 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 us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties over whom we 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, we 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. Our 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 our facilities, and impose various monitoring and reporting requirements. Pursuant to these laws and regulations, we 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. We 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 our financial condition or operating results, and the requirements are not expected to be more burdensome to us 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 our 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 us to incur monitoring and reporting costs for emissions that are subject to the rule. Some of our 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 our 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 our operations, but standards eventually promulgated pursuant to these findings could affect our 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 our 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 we conduct business could adversely affect the demand for the products we store, transport, and process, and depending on the particular program adopted could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our 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 our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our 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. We believe that we are 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 our 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 our customers, particularly in Barnett Shale and Haynesville Shale regions of our 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 our customers to perform hydraulic fracturing. Any increased federal, state or local regulation could reduce the volumes of natural gas that our customers move through our gathering systems which would materially adversely affect our revenues and results of operations.

Employee Safety. We are 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. We believe that our 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. Our 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 our 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. We believe that our 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 our 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 our south Louisiana operations in Houston, Texas with lease terms expiring in January 2013 and approximately 11,800 square feet of office space for our North Texas operations in Fort Worth, Texas with lease terms expiring in April 2013.

Employees

As of December 31, 2009, we (through our Operating Partnership) employed approximately 456 full-time employees. Approximately 244 of our employees were general and administrative, engineering, accounting and commercial personnel and the remainder were operational employees. We are not party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe that we have good relations with our 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 make distributions to our unitholders and the trading price of our common units 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.

Risks Inherent In Our Business

Our profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.

We are subject to significant risks due to fluctuations in commodity prices. We are directly exposed to these risks primarily in the gas processing component of our business. We are 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 our assets and on our margins for transportation between certain market centers. A large percentage of our processing fees are realized under percent of liquids (POL) contracts that are directly impacted by the market price of NGLs. We also realize 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 our 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 we are 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 our gross margin from processing.

We have a number of contracts on our Plaquemine and Gibson processing plants that expose us to the fractionation spread. Under these margin contracts our 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 our gross margin in the future if we have such declines again.

In the past, the prices of natural gas and NGLs have been extremely volatile and we expect 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 our 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;

	•		the availability of downstream NGL fractionation facilities;
	•		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 our profitability by influencing drilling activity and well operations, and thus the volume of gas we gather and process. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our hedging strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all of our throughput volumes. Moreover, hedges are subject to inherent risks, which we describe in “—Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.” For a discussion of our risk management activities, please read “Item 7A. Quantitative and Qualitative Disclosure about Market Risk.”

Our substantial indebtedness could limit our flexibility and adversely affect our financial health.

We have a substantial amount of indebtedness. As of December 31, 2009, we 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 our senior unsecured notes and borrowings under our new credit facility, we 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. We also had approximately $179.4 million of letters of credit outstanding under our old credit facility as of February 12, 2010 that were subsequently replaced by letters of credit under the new credit facility.

Our substantial indebtedness could limit our flexibility and adversely affect our financial health. For example, it could:

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make us more vulnerable to general adverse economic and industry conditions;

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

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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

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

In addition, our ability to make scheduled payments or to refinance our obligations depends on our successful financial and operating performance. We cannot assure you that our operating performance will generate sufficient cash flow or that our capital resources will be sufficient for payment of our indebtedness obligations in the future. Our 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 our control.

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

We may not be able to obtain additional funding for future capital needs or to refinance our 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 our 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, we cannot be certain that new debt or equity financing will be available to us on acceptable terms or at all. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Without adequate funding, we may be unable to execute our 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 our revenues and results of operations. Further, our customers may increase collateral requirements from us, including letters of credit which reduce available borrowing capacity, or reduce the business they transact with us to reduce their credit exposure to us.

Due to current economic conditions, our ability to obtain funding under our new credit facility could be impaired.

We operate in a capital-intensive industry and rely on our new credit facility to assist in financing a significant portion of our capital expenditures. Our ability to borrow under our new credit facility may be impaired. Specifically, we may be unable to obtain adequate funding under our new credit facility because:

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one or more of our 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 we are unable to access funds under our new credit facility, we will need to meet our capital requirements, including some of our 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 our operations or the funds we are able to obtain under our new credit facility or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on our results of operations and financial condition.

Due to our lack of asset diversification, adverse developments in our gathering, transmission, processing and producer services businesses would materially impact our financial condition.

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

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

Many of our 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 we otherwise would have seen being transported on our pipeline and gathering systems and processing through our processing plants. We saw a decline in drilling activity by gas producers in our 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 our operations.

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

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders. Many of our 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 our 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 our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our 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 us.

Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

Our operations expose us to fluctuations in commodity prices, and our new credit facility exposes us to fluctuations in interest rates. We use 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 our exposure to short-term volatility in commodity prices and interest rates. As of December 31, 2009, we have hedged only portions of our 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 we hedge our commodity price and interest rate risks using swap instruments, we will forego the benefits of favorable changes in commodity prices or interest rates. In February 2010, we settled all of our interest rate swaps associated with our old credit facility when we repaid the debt outstanding under this facility.

Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our 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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our 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 we seek protection. For example:

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the duration of a hedge may not match the duration of the risk against which we seek protection;

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

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

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

We may not be successful in balancing our purchases and sales.

We are a party to certain long-term gas sales commitments that we satisfy through supplies purchased under long-term gas purchase agreements. When we enter into those arrangements, our sales obligations generally match our purchase obligations. However, over time the supplies that we have under contract may decline due to reduced drilling or other causes and we 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 our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

We make 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 our margins or even result in losses. For example, we are a party to one contract where we buy gas on several different production-area indices on our NTP and sell 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.

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

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

In order to maintain or increase throughput levels in our natural gas gathering systems and asset utilization rates at our processing plants and to fulfill our current sales commitments, we must continually contract for new natural gas supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new wells to our gathering facilities include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near our 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 our systems. We have no control over producers and depend on them to maintain sufficient levels of drilling activity. A material decrease in natural gas production or in the level of drilling activity in our principal geographic areas for a prolonged period, as a result of depressed commodity prices or otherwise, likely would have a material adverse effect on our results of operations and financial position.

We are vulnerable to operational, regulatory and other risks due to our concentration of assets in south Louisiana and the Gulf of Mexico, including the effects of adverse weather conditions such as hurricanes.

Our operations and revenues will be significantly impacted by conditions in south Louisiana and the Gulf of Mexico because we have a significant portion of our assets located in south Louisiana and the Gulf of Mexico. In 2008, our 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 our gross margins of approximately $22.9 million in the last half of 2008. Although we 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 our south Louisiana plants did not recover to pre-hurricane levels until September 2009.

Our concentration of activity in Louisiana and the Gulf of Mexico makes us more vulnerable than many of our 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 our operations could experience the same condition at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other midstream companies who have operations in more diversified geographic areas.

In addition, our 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 our financial condition and results of operations.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our 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 our 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 we serve and any increased federal, state or local regulation could reduce the volumes of natural gas that they move through our gathering systems which would materially adversely affect our revenues and results of operations.

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

Growing our business by constructing new pipelines and processing facilities subjects us 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 we intend to grow our 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, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our 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 our expected investment return, which could adversely affect our results of operations and financial condition. In addition, we face 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 we expand our operations into more urban, populated areas such as the Barnett Shale.

Acquisitions typically increase our debt and subject us to other substantial risks, which could adversely affect our results of operations.

From time to time, we may evaluate and seek to acquire assets or businesses that we believe complement our existing business and related assets. We may acquire assets or businesses that we plan 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 our 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 our operations and cash flows. If we consummate any future acquisition, our 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 we will consider in determining the application of these funds and other resources.

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

We expect to encounter significant competition in any new geographic areas into which we seek to expand and our ability to enter such markets may be limited.

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

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

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

In particular, our ability to renew or replace our existing contracts with industrial end-users and utilities impacts our profitability. For the year ended December 31, 2009, approximately 48.5% of our sales of gas that was transported using our 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 us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price.

We depend on certain key customers, and the loss of any of our key customers could adversely affect our financial results.

We derive a significant portion of our 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, we would be adversely affected unless we were 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.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.

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

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

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inadvertent damage from construction and farm equipment;

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leaks of natural gas, NGLs and other hydrocarbons; and

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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 our related operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are 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 our operations and financial condition.

The threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact our results of operations and our 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. Our insurance policies generally exclude acts of terrorism. Such insurance is not available at what we believe to be acceptable pricing levels.

Federal, state or local regulatory measures could adversely affect our business.

Our 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. Our 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. We cannot predict what effect, if any, such changes might have on our 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 we transport natural gas in our pipeline systems in interstate commerce are subject to FERC regulation under the Section 311 of the Natural Gas Policy Act. Under these regulations, we are required to justify our rates for interstate transportation service on a cost-of-service basis, every three years. Our 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 our rates for Section 311 transportation service or intrastate transportation service should be lowered, our business could be adversely affected.

Other state and local regulations also affect our business. We are subject to some ratable take and common purchaser statutes in the states where we 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 our right as an owner of gathering facilities to decide with whom we 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 we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate 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 we conduct 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 our 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 our 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. Our 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. We expect the costs for compliance with TRRC and DOT regulations to be approximately $3.7 million during 2010. If our pipelines fail to meet the safety standards mandated by the TRRC or the DOT regulations, then we may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

As our operations continue to expand into and around urban, or more populated areas, such as the Barnett Shale, we may incur additional expenses to mitigate noise, odor and light that may be emitted in our operations, and expenses related to the appearance of our 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 our facilities and requiring certain other improvements that increase the cost of our facilities. We are also subject to claims by neighboring landowners for nuisance related to the construction and operation of our facilities, which could subject us to damages for declines in neighboring property values due to our construction and operation of facilities.

Our business involves hazardous substances and may be adversely affected by environmental regulation.

Many of the operations and activities of our 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 our facilities and the cleanup of hazardous substances and other wastes that may have been released at properties currently or previously owned or operated by us or locations to which we have 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 our facilities or upon or through which our 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 our business due to our handling of natural gas and other petroleum substances, air emissions related to our 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 our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us.

Our 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 our 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 our profitability. Changes in laws or regulations could also limit our production or the operation of our assets or adversely affect our ability to comply with applicable legal requirements or the demand for natural gas, which could adversely affect our business and our profitability.

Our success depends on key members of our management, the loss or replacement of whom could disrupt our business operations.

We depend on the continued employment and performance of the officers of the general partner of our general partner and key operational personnel. The general partner of our 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, our business operations could be materially adversely affected. We do not maintain any “key man” life insurance for any officers.

Risk Inherent In An Investment In the Partnership

Crosstex Energy, Inc., or CEI, controls our general partner and owned a 25.0% limited partner interest in us as of January 31, 2010. Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests.

As of January 31, 2010, CEI indirectly owned an aggregate limited partner interest of approximately 25.0% in us. In addition, CEI owns and controls our general partner. Due to its control of our general partner and the size of its limited partner interest in us, CEI effectively controls all limited partnership decisions, including any decisions related to the removal of our general partner. Conflicts of interest may arise in the future between CEI and its affiliates, including our general partner, on the one hand, and our partnership, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over our interests. These conflicts include, among others, the following situations:

Conflicts Relating to Control

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our partnership agreement limits our general partner’s liability and reduces its fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without these limitations, constitute breaches of fiduciary duty by our general partner;

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in resolving conflicts of interest, our general partner is allowed to take into account the interests of parties in addition to unitholders, which has the effect of limiting its fiduciary duties to the unitholders;

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our general partner’s affiliates may engage in limited competition with us;

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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us;

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in some instances our general partner may cause us to borrow funds from affiliates of the general partner or from third parties in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions; and

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our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves also will affect the amount of cash available for distribution.

Conflicts Relating to Costs:

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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves, each of which can affect the amount of cash that is available for the payment of principal and interest on the notes;

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us; and

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our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our unitholders have no right to elect our general partner or the directors of its general partner and have limited ability to remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of its general partner and have no right to elect our general partner or the board of directors of its general partner on an annual or other continuing basis.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 66 2/3% of the outstanding units voting together as a single class. Affiliates of the general partner controlled approximately 27.0% of all the units as of January 31, 2010.

In addition, unitholders’ voting rights are further restricted by the partnership agreement. It provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of the general partner’s general partner, cannot be voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

As a result of these provisions, it will be more difficult for a third party to acquire our partnership without first negotiating such a purchase with our general partner and, as a result, our unitholders are less likely to receive a takeover premium.

Cost reimbursements due our general partner may be substantial and will reduce the cash available for distribution to our unitholders.

Prior to making any distributions on the units, we reimburse our general partner and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to make distributions to our unitholders. Our general partner has sole discretion to determine the amount of these expenses.

The control of our general partner may be transferred to a third party, and that third party could replace our current management team.

The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of the general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.

Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to our unitholders.

Our partnership agreement contains provisions that reduce the remedies available to our unitholders for actions that might otherwise constitute a breach of fiduciary duty by our general partner.

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. The partnership agreement also restricts the remedies available to our unitholders for actions that would otherwise constitute breaches of our general partner’s fiduciary duties. If you choose to purchase a common unit, you will be treated as having consented to the various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary duties under applicable state law.

We may issue additional units without our unitholders’ approval, which would dilute our unitholders’ ownership interests.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional limited partner interests will have the following effects:

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our unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash available for distribution on each unit may decrease;

	•		the relative voting strength of each previously outstanding unit may be diminished; and
	•		the market price of the common units may decline.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.

Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

Our unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders to remove or replace our general partner, to approve amendments to our partnership agreement, or to take other action under our partnership agreement constituted participation in the “control” of our business, to the extent that a person who has transacted business with the partnership reasonably believes, based on our unitholders’ conduct, that our unitholders are a general partner. Our general partner generally 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 our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of that section may be liable to the limited partnership for the amount of the distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.

Tax Risks to Our Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity level taxation by individual states. If the IRS treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to you.

The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay additional tax on our income at corporate rates of up to 35.0% (under the law as of the date of this report) and we would probably pay state income taxes as well. In addition, distributions to unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses, or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders and thus would likely result in a material reduction in the value of the common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, members of Congress have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the legislation considered would not have appeared to affect our tax treatment, we are unable to predict whether any such change or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. At the state level, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 1.0% of our gross income apportioned to Texas in the prior year. If federal income tax or material amounts of additional state tax were to be imposed on us, the cash available for distribution to unitholders could be reduced and/or the value of an investment in our common units would be adversely impacted. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be decreased to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any contest could reduce the cash available for distribution to our unitholders.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this annual report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne by us and therefore indirectly by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution by us.

Unitholders may be required to pay taxes on our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, they will be required to pay federal income taxes and, in some cases, state, local, and foreign income taxes on their share of our taxable income even if they do not receive cash distributions from us. Unitholders may not receive cash distributions equal to their share of our taxable income or even the tax liability that results from that income. We do not currently expect to pay a distribution until late 2010 or 2011.

Tax gain or loss on the disposition of our common units could be different than expected.

Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated for a common unit, which decreased the tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, a unitholder who sells units may incur a tax liability in excess of the amount of cash received from the sale. As a result of the foregoing, unitholders who sell units may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), pension plans, and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other qualified retirement plans, will be unrelated business income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

We will determine the tax benefits that are available to an owner of units without regard to the specific units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of unitholders.

The sale or exchange of 50% or more of our capital and profits interests within a 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder who has adopted a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination would cause us to be treated as a new partnership for tax purposes, and we could be subject to penalties if we were to fail to recognize and properly report on our tax return that a termination occurred.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from profits interests in partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

As a result of investing in our common units, you will likely be subject to state and local taxes and return filing or withholding requirements in jurisdictions where you do not live.

In addition to federal income taxes, you will likely be subject to other taxes such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file state and local tax returns and pay state and local income taxes in some or all of the various jurisdictions in which we do business or own property and you may be subject to penalties for failure to comply with those requirements. We own property or conduct business in Texas and Louisiana. Louisiana imposes an income tax, generally. Texas does not impose a state income tax on individuals, but does impose a franchise tax to which we are subject. We may do business or own property in other states or foreign countries in the future. It is our unitholders’ responsibility to file all federal, state, local, and foreign tax returns. Under the tax laws of some states where we will conduct business, we may be required to withhold a percentage from amounts to be distributed to a unitholder who is not a resident of that state. Our counsel has not rendered an opinion on the state, local, or foreign tax consequences of owning our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We (or our subsidiaries) are defending several lawsuits filed by owners of property located near processing facilities or compression facilities constructed by us as part of our 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, we do 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 us approximately $6.2 million, including approximately $3.9 million for June 2008 sales and approximately $2.3 million for July 2008 sales. We believe the July sales of $2.3 million will receive “administrative claim” status in the bankruptcy proceeding. The debtor’s schedules acknowledge its obligation to us for an administrative claim in the amount of $2.3 million, but it remains subject to an objection by the lenders’ agent. We evaluated these receivables for collectibility and recorded a provision for bad debts 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

Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations. Our distributions are effectively made 98.0% to unitholders and two percent to our general partner, subject to the payment of incentive distributions to our general partner if certain target cash distribution levels to common unitholders are achieved. Incentive distributions to our general partner increase to 13.0%, 23.0% and 48.0% based on incremental distribution thresholds as set forth in our partnership agreement.

Our ability to make distributions was contractually restricted by the terms of our credit facilities during 2009 due to our high leverage ratios. Although our new credit facility does not limit our ability to make distributions as long as we are not in default of such facility (and the indenture governing our senior unsecured notes requires us to meet a ratio test), any decision to resume cash distributions on our 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 ratios. We have 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 we do not currently expect to resume cash distributions on our outstanding units until we achieve such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). We will also consider general economic conditions and our outlook for our business as we determine to pay any distribution.

On January 19, 2010, we 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. We have 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 we deliver 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 we deliver 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 we pay a cash distribution on common units.

Item 6.		Selected Financial Data

The following table sets forth selected historical financial and operating data of Crosstex Energy, L.P. 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, L.P. and have been revised to reflect 2009 asset dispositions as discontinued operations and to move letter of credit fees to interest expense from purchased gas expense. In addition, our summary historical financial and operating data include the results of operations of the south Louisiana processing assets beginning November 2005, the NTP beginning April 2006 and the Chief midstream assets beginning June 2006 and other smaller acquisitions completed in 2006.

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

We also realize margins from our processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fee based. Under the margin contract arrangements our 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 our 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.

Our general and administrative expenses are dictated by the terms of our partnership agreement. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of business and allocable to us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.

Recent Developments and Business Strategy

From our inception in 2002 until the second half of 2008, our 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, we adjusted our business strategy in the fourth quarter 2008 and in 2009 to focus on maximizing our liquidity, improving our balance sheet through debt reduction and other methods, maintaining a stable asset base, improving the profitability of our assets by increasing their utilization while controlling costs and reducing our capital expenditures. Consistent with this strategy, we divested non-core assets since October 2008 for aggregate sale proceeds of $618.7 million and substantially reduced our outstanding debt. We plan to continue our focus on (i) improving existing system profitability, (ii) continuing to improve our balance sheet and financial flexibility and (iii) pursuing strategic acquisitions and undertaking selective construction and expansion opportunities. We are successfully executing our plan as highlighted by the following accomplishments:

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Sold Non-Core Assets. We 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 we sold our 12.4% interest in the Seminole gas processing plant for $85.0 million. In the first quarter of 2009, we sold our Arkoma system for approximately $10.7 million. In August 2009, we sold our midstream assets in Alabama, Mississippi and south Texas for approximately $217.6 million. In addition, in October 2009, we sold our natural gas treating business for $265.4 million. We also sold our east Texas midstream assets on January 15, 2010 for $40.0 million.

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

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Reduced Operating and General and Administrative Expenses. We reduced our 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 our 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.

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Acquired Certain Assets in Our Core Areas. We 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. We 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. We 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 our NGL business.

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Sale of Preferred Units. On January 19, 2010, we 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. We have 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 we deliver 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 we deliver 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 we pay a cash distribution on common units.

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Issuance of Senior Unsecured Notes. On February 10, 2010, we 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 our new credit facility discussed below, were used to repay in full amounts outstanding under our 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 our 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. We have 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, we may redeem the notes, in whole or in part, at a “make-whole” redemption price. In addition, we 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, we amended and restated our existing secured bank credit facility with a new syndicated secured bank credit facility, which will be guaranteed by substantially all of our 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 our 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 our equity interests in substantially all of our subsidiaries. Under the new credit facility, borrowings will bear interest at our 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. We will pay a per annum fee on all letters of credit issued under the new credit facility, and we 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 our interest rate vary quarterly based on our leverage ratio.

Acquisitions and Expansion Prior to 2009

We grew significantly through asset purchases and construction and expansion projects in years prior to 2009. As discussed above, we disposed of certain assets during late 2008 and 2009 to refocus our 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 our business during 2006, 2007, 2008 and 2009. We also acquired treating assets during 2006 that were included in the sale of our Treating business in 2009 as discussed above.

On June 29, 2006, we expanded our operations in the north Texas area through our 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, we began expanding our north Texas pipeline gathering system. The continued expansion of our north Texas gathering systems to handle the growing production in the Barnett Shale was one of our core areas for internal growth during 2006, 2007, 2008 and 2009. Since the date of the acquisition through December 31, 2009, we have expanded our gathering system, connected in excess of 500 new wells to our north Texas gathering system and significantly increased the productive acreage dedicated to our systems. As of December 31, 2009, total capacity on our 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, we have constructed three gas processing plants with a total processing capacity in the Barnett Shale of 280 MMcf/d, including our Silver Creek plant, which is a 200 MMcf/d cryogenic processing plant, our Azle plant, which is a 50 MMcf/d cryogenic processing plant and our 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, we extended our 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. Our 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 we 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. We continued the expansion of our north Louisiana system during 2009 increasing capacity by 100 MMcf/d in July 2009 by adding compression. We increased our 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. We have long-term firm transportation agreements subscribing to all of the incremental capacity added during 2009. In addition, we added compression during 2009 between the southern portion of our Crosstex LIG system and the northern expansion of our Crosstex LIG system, which increased the capacity to bring gas from the north to our 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.

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our exposure to these risks is primarily in the gas processing component of our business. A large percentage of our processing fees are realized under POL contracts that are directly impacted by the market price of NGLs. We also realize 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 our 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 we are 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 our gross margin from processing.

We have a number of margin contracts on our Plaquemine and Gibson processing plants that expose us to the fractionation spread. Under these margin contracts our 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 our gross margin in the future if we have such declines again.

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

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.

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 our 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 year 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 year 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 $59.9 million for the year ended December 31, 2009 compared to $68.9 million for the year ended December 31, 2008, a decrease of $9.0 million, or 13.1%. 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 . We had a gain on derivatives of $3.0 million for the year ended December 31, 2009 compared to a gain 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):

Impairments . During the year ended December 31, 2009, we had an impairment expense of $2.9 million compared to $29.4 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:

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$17.8 million related to the Blue Water gas processing plant located in south Louisiana — The impairment on our 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 our 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, we had not found an alternative source of new gas for the Blue Water plant 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 the estimated fair value of the plant as of December 31, 2008.

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$4.9 million related to goodwill — We determined that the carrying amount of goodwill attributable to the Midstream segment was impaired because of the significant decline in our 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.

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$4.1 million related to leasehold improvements — We had planned to relocate our corporate headquarters during 2008 to a larger office facility. We had leased office space and were close to completing the renovation of this office space when the global economic decline began impacting our 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.

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$2.6 million related to the Arkoma gathering system — The impairment on the Arkoma gathering system was recognized because we sold this asset 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 $119.1 million for the year ended December 31, 2009 compared to $107.5 million for the year ended December 31, 2008, an increase of $11.6 million, or 10.8%, 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 $75.0 million for the year ended December 31, 2008, an increase of $20.1 million, or 26.8%. Net interest expense consists of the following (in millions):

Loss on Extinguishment of Debt. We 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 $27.8 million for the year ended December 31, 2008. In November 2008, we 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. Income tax expense was $1.8 million for the year ended December 31, 2009 compared to $2.4 million for the year ended December 31, 2008, a decrease of $0.6 million. The decrease in expense between periods was because the income tax expense for the year ended December 31, 2008 included an adjustment of $0.9 million for an unrecognized tax benefit related to the Texas margin tax.

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

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, we expensed $4.3 million in borrowings of unamortized debt issuance costs associated with the bank credit facility and the senior secured notes due to the repayments 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, 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 our gathering and transmission systems. These increases were partially offset by margin decreases in the processing business due to a less favorable NGL market and operating downtime due to the impact of 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 gathering systems in the region and NTP accounted for $41.3 million and $9.1 million of this increase, respectively. The 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 due to the impact of hurricanes along the Gulf Coast.

Our processing and gathering systems were negatively impacted by events beyond our control during the third quarter that had a significant effect on gross margin results for the year ended December 31, 2008. Hurricanes Gustav and Ike came ashore along the Gulf Coast in September 2008. These storms are estimated to have cost approximately $22.9 million in gross margin 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 plant in August 2008 due to downtime from fire damage. The fire occurred during an attempt to bring the plant back online 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 $34.6 million, or 37.9%, 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:

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Contractor services and labor costs increased $12.3 million;

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Chemical and materials increased $6.2 million;

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Equipment rental increased $5.8 million;

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Ad valorem taxes increased $2.2 million; and

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Technical services increased $0.7 million.

General and Administrative Expenses . General and administrative expenses were $68.9 million for the year ended December 31, 2008 compared to $59.5 million for the year ended December 31, 2007, an increase of $9.4 million, or 15.8%. The increase is primarily attributable to the following factors:

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$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;

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

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$1.8 million increase in professional fees and services; and

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$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 . We had a gain on derivatives of $8.6 million for the year ended December 31, 2008 compared to a gain 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):

Impairments . During the year ended December 31, 2008, we had an impairment expense of $29.4 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 $107.5 million for the year ended December 31, 2008 compared to $83.3 million for the year ended December 31, 2007, an increase of $24.2 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 $75.0 million for the year ended December 31, 2008 compared to $48.1 million for the year ended December 31, 2007, an increase of $26.9 million, or 56.0%. The increase relates primarily to the negative impact of declining interest rates on our interest rate swaps. Net interest expense consists of the following (in millions):

Other Income . Other income was $27.8 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 and $7.0 million from the settlement of disputed liabilities that were assumed with an acquisition.

Income Taxes . Income tax expense was $2.4 million for the year ended December 31, 2008 compared to $0.8 million for the year ended December 31, 2007, an increase of $1.6 million. The increase relates primarily to the Texas margin tax.

Discontinued Operations . Income from discontinued operations was $74.8 million for the year ended December 31, 2008 compared to $31.3 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.

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 . We recognize revenue for sales or services at the time the natural gas or NGLs are delivered or at the time the service is performed. We generally accrue one month of sales and the related gas purchases and reverse these accruals when the sales and purchases are actually invoiced and recorded in the subsequent months. Actual results could differ from the accrual estimates.

We utilize 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. We use 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. We believe that our accrual process for sales and purchases provides a reasonable estimate of such sales and purchases.

We engage in price risk management activities in order to minimize the risk from market fluctuations in the price of natural gas and NGLs. We also manage our 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 our future commitments and significantly reduce our risk to the movement in natural gas prices.

We use derivatives to hedge against changes in cash flows related to product prices and interest rate risks, 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.

We conduct “off-system” gas marketing operations as a service to producers on systems that we do not own. We refer to these activities as part of energy trading activities. In some cases, we earn an agency fee from the producer for arranging the marketing of the producer’s natural gas. In other cases, we purchase the natural gas from the producer and enter 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.

We manage our 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, we are subject to counter-party risk for both the physical and financial contracts. Our energy trading contracts qualify as derivatives, and we use 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.

Impairment of Long-Lived Assets . In accordance with FASB ASC 360-10-05, we evaluate 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 our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset. Our 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:

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

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the availability and prices of natural gas supply;

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our ability to negotiate favorable sales agreements;

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

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our dependence on certain significant customers, producers, and transporters of natural gas; and

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competition from other midstream companies, including major energy producers.

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

Depreciation Expense and Cost Capitalization . Our assets consist primarily of natural gas gathering pipelines, processing plants, and transmission pipelines. We capitalize 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. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

We generally compute 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, we may review depreciation estimates 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 $81.0 million, $173.8 million and $114.8 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):

The primary reason for the decreased cash flow from income before non-cash income and expenses of $71.1 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 $22.0 million from 2007 to 2008 was increased operating income from our expansions in north Texas and north Louisiana during 2007 and 2008.

Cash Flows from Investing Activities. Net cash was provided from investing activities of $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 our Alabama, Mississippi, south Texas and Treating assets. Sales in 2008 primarily relate to the sale of our interest in the Seminole gas processing plant. The 2007 sales primarily relate to sales of inactive properties. Our primary investing activities for 2009, 2008 and 2007 were capital expenditures and acquisitions, net of accrued amounts, as follows (in millions):

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. We disposed of non-core assets and repaid outstanding debt which resulted in net cash used by financing activities of $461.7 million for the year ended December 31, 2009. Net cash provided by financing activities was $14.6 million and $295.9 million for the years ended December 31, 2008 and 2007, respectively. Our financing activities primarily relate to funding of capital expenditures and acquisitions. Our financings have primarily consisted of borrowings and repayments under our bank credit facility, payments on senior secured notes, borrowings under capital lease obligations, equity offerings and senior note issuances in 2009, 2008 and 2007 as follows (in millions):

Historically distributions to unitholders and our general partner represented our primary use of cash in financing activities. We ceased making distributions in the first quarter of 2009 due to liquidity issues and because the terms of our previous credit facility and senior secured note agreement restricted our ability to make distributions unless certain conditions were met. We did not meet these conditions during 2009. Total cash distributions made during the last three years were as follows (in millions):

Our ability to make distributions was contractually restricted by the terms of our credit facilities during 2009 due to our high leverage ratios. Although our new credit facility does not limit our ability to make distributions as long as we are not in default of such facility (and the indenture governing our senior unsecured notes requires us to meet a ratio test), any decision to resume cash distributions on our 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 ratios. We have 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 we do not currently expect to resume cash distributions on our outstanding units until we achieve such a ratio of less than 4.5 to 1.0 (pro forma for any distribution). We will also consider general economic conditions and our outlook for our business as we determine to pay any distribution.

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

Working Capital Deficit. We had a working capital deficit of $50.3 million as of December 31, 2009, primarily due to a net liability for our fair value of derivatives of $21.3 million and our current portion of long-term debt of $28.6 million related to our senior secured notes. Our 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, we repaid in full our senior secured notes and settled our interest rate swaps. Our changes in working capital may fluctuate significantly between periods even though our trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of our revenues are collected and a large volume of our gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end my fluctuate significantly depending on the timing of these receipts and payments. In addition, although we strive to minimize our natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period to period due to operational reasons and due to changes in natural gas and NGL prices. Our working capital also includes our mark to market derivative assets and liabilities associated with our commodity derivatives which may fluctuate significantly due to the changes in natural gas and NGL prices and associated with our 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, we 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. We have 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 we deliver 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 we deliver 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 we pay a cash distribution on common units. The preferred units were issued at a discount to the market price of the common units they are convertible into. This discount totaling $22.3 million represents a beneficial conversion feature that will be reflected as a reduction in common unit equity upon issuance of the preferred units (which occurred on January 19, 2010) and will reduce earnings per common unit.

April 2008 Sale of Common Units. On April 9, 2008, we 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. Crosstex Energy GP, L.P. made a general partner contribution of $2.0 million in connection with the issuance to maintain its 2% general partner interest.

December 2007 Sale of Common Units. On December 19, 2007, we issued 1,800,000 common units at a price of $33.28 per unit for net proceeds of $57.6 million. In addition, Crosstex Energy GP, L.P. made a general partner contribution of $1.2 million in connection with the issuance to maintain its 2% general partner interest.

March 2007 Sale of Senior Subordinated Series D Units. On March 23, 2007, we 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. Crosstex Energy GP, L.P. made a general partner contribution of $2.7 million in connection with this issuance to maintain its 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 units 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 us until March 23, 2009.

Capital Requirements of the Partnership. We reduced our capital expenditures significantly for 2009 to improve our liquidity. Total capital expenditures during 2009 were less than $101.4 million. We utilized cash flow from operations and existing capacity under our bank credit facility to fund such expenditures. Our 2010 capital budget includes approximately $25.0 million of identified growth projects, and we expect to fund such expenditures with internally generated cash flow, with any excess cash flow applied towards debt, working capital or new projects. Although we expect to identify more growth projects during 2010 in addition to projects currently budgeted, we do not anticipate that our capital expenditures during 2010 will exceed $100.0 million.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2009 is as follows (in millions):

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):

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, we 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, we amended and restated our 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 this credit facility along with net proceeds from the senior unsecured notes were used to, among other things, repay the previous bank credit facility and the senior secured notes.

The new credit facility will be guaranteed by substantially all of our subsidiaries. Obligations under the new credit facility will be secured by first priority liens on substantially all of our 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 our equity interests in substantially all of our subsidiaries.

We 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. We will pay a per annum fee on all letters of credit issued under the new credit facility, and we 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 our interest rate will vary quarterly based on our 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:

Based on our forecasted leverage ratio for 2010, we expect 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:

•

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

•

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

•

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

•

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

•

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

•

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:

•

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

•

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

•

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

•

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

•

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 our ability to:

•

grant or assume liens;

•

make investments;

•

incur or assume indebtedness;

•

engage in mergers or acquisitions;

•

sell, transfer, assign or convey assets,

•

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

•

change the nature of our business;

•

engage in transactions with affiliates.

•

enter into certain burdensome agreements;

•

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

•

prepay the senior unsecured notes and certain other indebtedness; and

•

enter into certain hedging contracts.

The new credit facility will permit us 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:

•

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

•

failure to meet the quarterly financial covenants;

•

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;

•

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

•

our or any of our subsidiaries’ default under other indebtedness that exceeds a threshold amount;

•

judgments against us or any of our material subsidiaries, in excess of a threshold amount;

•

certain ERISA events involving us or any of our material subsidiaries, in excess of a threshold amount;

•

bankruptcy or other insolvency events involving us or any of our material subsidiaries; and

•

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 we are unable to make any of the representations and warranties in the new credit facility, we will be unable to borrow funds or have letters of credit issued under the new credit facility.

We will be subject to interest rate risk on our new credit facility and may enter into interest rate swaps to reduce this risk.

We expect 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):

Series B Secured Note. On October 20, 2009, the Partnership acquired the Eunice natural gas liquids processing plant and fractionation facility which includes $18.1 million in series B secured note. This note bears an interest rate of 9.5%. Payments including interest of $12.2 million and $7.4 million are due in 2010 and 2011, respectively.

Senior Unsecured Notes. On February 10, 2010, we issued $725.0 million in aggregate principal amount of 8.875% senior unsecured notes due on February 15, 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 our new credit facility discussed above, were used to repay in full amounts outstanding under our 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 our existing credit facility. The notes are unsecured and unconditionally guaranteed on a senior basis by certain of our direct and indirect subsidiaries, including all of our current subsidiaries other than Crosstex LIG, LLC and Crosstex Tuscaloosa, LLC, our Louisiana regulated entities, and Crosstex DC Gathering, J.V. Interest payments will be paid semi-annually in arrears starting on August 15, 2010.

The indenture governing the notes contains covenants that, among other things, will limit our ability and the ability of certain of our subsidiaries to:

•

sell assets including equity interests in our subsidiaries;

•

pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;

•

make investments;

•

incur or guarantee additional indebtedness or issue preferred units;

•

create or incur certain liens;

•

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

•

consolidate, merge or transfer all or substantially all of our assets;

•

engage in transactions with affiliates;

	•		create unrestricted subsidiaries;
	•		enter into sale and leaseback transactions; or

•

engage in certain business activities.

If the notes achieve an investment grade rating from each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, many of these covenants will terminate.

We may redeem up to 35% of the notes at any time prior to February 15, 2013 with the cash proceeds from equity offerings at a redemption price of 108.875% (of the principal amount plus accrued and unpaid interest to the redemption date), provided that:

•

at least 65% of the aggregate principal amount of the senior notes remains outstanding immediately after the occurrence of such redemption; and

•

the redemption occurs within 120 days of the date of the closing of the equity offering.

Prior to February 15, 2014, we may redeem the notes, in whole or in part, at a “make-whole” redemption price. On or after February 15, 2014, we may redeem all or a part of the notes at redemption prices (expressed as percentages of principal amount) equal to 104.438% for the twelve-month period beginning on February 15, 2014, 102.219% for the twelve-month period beginning February 15, 2015 and 100.00% for the twelve-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the notes.

Each of the following will be an event of default under the indenture:

•

failure to pay any principal or interest when due;

•

failure to observe any other agreement, obligation, or other covenant in the indenture, subject to the cure periods for certain failures; and

•

our or any of our subsidiaries’ default under other indebtedness that exceeds a certain threshold amount;

•

failures by us or any of our subsidiaries to pay final judgments that exceed a certain threshold amount; and

•

bankruptcy or other insolvency events involving us or any of our material subsidiaries.

If an event of default relating to bankruptcy or other insolvency events occurs, the senior unsecured notes will immediately become due and payable. If any other event of default exists under the indenture, the trustee under the indenture or the holders of the senior unsecured notes may accelerate the maturity of the senior unsecured notes and exercise other rights and remedies.

Credit Risk

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Any increase in the nonpayment and nonperformance by our customers could adversely affect our results of operations and reduce our ability to make distributions to our unitholders. Many of our 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 our 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 our customers’ liquidity and ability to make payments or perform on their obligations to us. Furthermore, some of our 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 us.

Inflation

Inflation in the United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry experienced an increase in labor and material costs during 2008, but 2009 remained relatively unchanged. These increases did not have a material impact on our results of operations for the periods presented. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Environmental

Our operations are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. We believe we are in material compliance with all applicable laws and regulations. For a more complete discussion of the environmental laws and regulations that impact us, see Item 1. “Business — Environmental Matters.”

Contingencies

In December 2008, Denbury initiated formal arbitration proceedings against Crosstex CCNG Processing Ltd. (“Crosstex Processing”), Crosstex Energy, Crosstex Gathering and 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 Denbury. We estimate that the total award will be between $3.0 million and $4.0 million at the conclusion of these additional proceedings. We have accrued $3.7 million in other current liabilities for this award as of December 31, 2009 and reflected the related expense in purchased gas costs.

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 inflate 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 provided a valuation allowance of $3.1 million and $0.8 million during the years ended December 31, 2008 and 2009, respectively.

Recent Accounting Pronouncements

As a result of the recent credit crisis, FASB ASC 820-10-35-15A was issued October 2008 and clarifies the application of FASB ASC 820 in a market that is not active and provides guidance on how observable market information in a market that is not active should be considered when measuring fair value, as well as how the use of market quotes should be considered when assessing the relevance of observable and unobservable data available to measure fair value. FASB ASC 820-10-35-15A is effective upon issuance, for companies that have adopted FASB ASC 820. We have evaluated FASB ASC 820-10-35-15A and determined that this standard has no impact on our results of operations, cash flows or financial position for this reporting period.

FASB ASC 260-10-45-60 was issued June 2008 and requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in FASB ASC 260-10-20 and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB ASC 260. FASB ASC 260-10-45-60 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. We adopted FASB ASC 260-10-45-60 effective January 1, 2009 and adjusted all prior periods to conform to the requirements.

FASB ASC 805 and FASB ASC 810-10-65-1 were issued December 2007. FASB ASC 805 requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under FASB ASC 805 all business combinations will be accounted for by applying the acquisition method. FASB ASC 805 is effective for periods beginning on or after December 15, 2008. FASB ASC 810-10-65-1 requires noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. FASB ASC 810-10-65-1 was adopted effective January 1, 2009 and comparative period information has been recast to classify non-controlling interests in equity, and attribute net income and other comprehensive income to non-controlling interests.

FASB ASC 105 was released July 1, 2009 and intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of non-governmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. SFAS No. 162 has been superseded by SFAS No. 168, “ The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (the Codification) released July 1, 2009. The Codification became the exclusive authoritative reference for non-governmental U.S. GAAP for use in financial statements issued for interim and annual periods ending after September 15, 2009, except for Securities and Exchange Commission (SEC) rules and interpretive releases, which are also authoritative GAAP for SEC registrants. The change establishes non-governmental U.S. GAAP into the authoritative Codification and guidance that is non-authoritative. The contents of the Codification carry the same level of authority, eliminating the four-level GAAP hierarchy previously set forth in Statement 162. The Codification supersedes all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification has become non-authoritative. We have revised all GAAP references to reflect the Codification for the year ended December 31, 2009.

FASB ASC 815-10-65-1 was issued March 2008 and requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under FASB ASC 815 and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. FASB ASC 815-10-65-1 is effective for fiscal years beginning after November 15, 2008. FASB ASC 815-10-65-1 was adopted effective January 1, 2009. Required disclosures were added to Note 13.

FASB ASC 260-10-55-102 was released in March 2008 and addresses the consensus reached by the Task Force that incentive distribution rights (IDRs) in a typical master limited partnership are participating securities under FASB ASC 260, but earnings in excess of the partnership’s “available cash” should not be allocated to the IDR holders for purposes of calculating earnings-per-share using the two-class method when “available cash” represents a specified threshold that limits participation. The consensus only applies when payments to IDR holders are accounted for as equity distributions. The consensus is effective for fiscal years beginning after December 15, 2008 and applied retrospectively to all periods presented. Under our partnership agreement, “available cash” is a specified threshold that limits participation for IDR holders. Therefore earnings in excess of our available cash, if any, are not allocated to IDR holders.

In June 2009 FASB ASC 810-10-05-8 was issued. It requires reporting entities to evaluate former Qualifying Special Purpose Entities or QSPEs for consolidation, changes the approach to determining a variable interest entity’s (VIE) primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. This statement requires additional year-end and interim disclosures for public and nonpublic companies that are similar to the disclosures required by FASB ASC 860-10-65-2. The statement is effective for fiscal years beginning after November 15, 2009 and for subsequent interim and annual reporting periods. We do not expect this statement to have a significant impact to its financial statements.

FASB ASC 855 was issued June 2009 and is effective for interim or annual financial periods ending after June 15, 2009 and addresses accounting and disclosure requirements related to subsequent events. The statement requires management to evaluate subsequent events through the date the financial statements are issued. Companies are required to disclose the date through which subsequent events have been evaluated. We have taken this statement into consideration in Note 18.

FASB ASC 825-10-65-1 requires publicly traded companies to disclose the fair value of financial instruments within the scope of FASB ASC 825 in interim financial statements, adding to the current requirement to make those disclosures in annual financial statements. FASB ASC 825-10-65-1 is effective for interim and annual periods ending after June 15, 2009. We have added the required footnote disclosure in interim financial statements.

Disclosure Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, that are based on information currently available to management as well as management’s assumptions and beliefs. All statements, other than statements of historical fact, included in this Form 10-K constitute forward-looking statements, including but not limited to statements identified by the words “may,” “will,” “should,” “plan,” “predict,” “anticipate,” “believe,” “intend,” “estimate” and “expect” and similar expressions. Such statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to the specific uncertainties discussed elsewhere in this Form 10-K, the risk factors set forth in “Item 1A. Risk Factors” may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Item 7A.		Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The Partnership’s primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, it is also exposed to the risk of changes in interest rates on floating rate debt.

Interest Rate Risk

We are exposed to interest rate risk on our variable rate bank credit facility. At December 31, 2009 and 2008, our bank credit facility had outstanding borrowings of $529.6 million and $784.0 million, respectively, which approximated fair value. We have managed a portion of our interest rate exposure on variable rate debt by utilizing interest rate swaps, which allow us to convert a portion of our variable rate interest into fixed rate interest. As of December 31, 2009, the fair value of these interest rate swaps was reflected as a liability of $24.7 million ($17.9 million in net current liabilities and $6.8 million in long-term liabilities) on our financial statements. We estimate that a 1% increase or decrease in the interest rate would increase or decrease the fair value of these interest rate swaps by approximately $12.7 million. Considering the amount outstanding on our bank credit facility as of December 31, 2009, we estimate that a 1% increase or decrease in the interest rate would change our annual interest expense by approximately $5.3 million.

At December 31, 2009 and 2008, we had total fixed rate debt obligations of $344.1 million and $479.7 million, respectively, consisting of senior secured notes with a weighted average interest rate of 10.5% and a series B secured note with a fixed rate of 9.5%. The fair value of these fixed rate obligations was approximately $342.7 million and $374.4 million as of December 31, 2009 and 2008, respectively. We estimate that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rated debt (the senior secured notes) by $9.6 million based on the debt obligations as of December 31, 2009.

The debt obligations discussed above and the related interest rate swaps were liquidated during February 2010 in the completion of our long-term recapitalization plan as discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Recent Developments and Business Strategy” under “Description of Indebtedness — Senior Unsecured Notes” and “Description of Indebtedness — New Credit Facility.”

Commodity Price Risk

We are subject to significant risks due to fluctuations in commodity prices. Our direct exposure to these risks is primarily in the gas processing component of our business. We currently process gas under three main types of contractual arrangements:

1.

Processing margin contracts : Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) and the cost of fuel used in processing. The shrink and fuel losses are referred to as plant thermal reduction or PTR. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, we mitigate our risk of processing natural gas when our margins are negative under our current processing margin contracts primarily through our ability to bypass processing when it is not profitable for us, or by contracts that revert to a minimum fee for processing if the natural gas must be processed to meet pipeline quality specifications.

2.

Percent of liquids contracts : Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under percent of liquids contracts, but do decline during periods of low NGL prices.

3.

Fee based contracts : Under these contracts we have no commodity price exposure and are paid a fixed fee per unit of volume that is processed.

The gross margin presentation in the table below is calculated net of results from discontinued operations. Gas processing margins by contract types and gathering and transportation margins as a percent of total gross margin for the comparative year-to-date periods are as follows: