10-K 1 d66491e10vk.htm FORM 10-K e10vk
Table of Contents

 
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, 2008
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number: 000-50067
CROSSTEX ENERGY, L.P.
(Exact name of registrant as specified in its charter)
 
     
Delaware
  16-1616605
(State of organization)   (I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS
DALLAS, TEXAS
(Address of principal executive offices)
  75201
(Zip Code)
 
(Registrant’s telephone number, including area code)
 
(214) 953-9500
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
     
Title of Each Class
 
Name of Exchange on which Registered
 
Common Units Representing Limited
Partnership Interests
  The NASDAQ Global Select Market
 
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 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 $437,179,020 on June 30, 2008, based on $28.68 per unit, the closing price of the Common Units as reported on the NASDAQ Global Select Market on such date.
 
At February 16, 2009, there were 44,942,955 common units and 3,875,340 senior subordinated series D units outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE:
None.
 


 

 
TABLE OF CONTENTS
 
DESCRIPTION
 
 
             
Item
      Page
 
1.
  BUSINESS     2  
1A.
  RISK FACTORS     20  
1B.
  UNRESOLVED STAFF COMMENTS     36  
2.
  PROPERTIES     37  
3.
  LEGAL PROCEEDINGS     37  
4.
  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS     38  
 
PART II
5.
  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES     38  
6.
  SELECTED FINANCIAL DATA     40  
7.
  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     42  
7A.
  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     66  
8.
  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     68  
9.
  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     68  
9A.
  CONTROLS AND PROCEDURES     68  
9B.
  OTHER INFORMATION     69  
 
PART III
10.
  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE     69  
11.
  EXECUTIVE COMPENSATION     73  
12.
  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS     89  
13.
  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE     92  
14.
  PRINCIPAL ACCOUNTING FEES AND SERVICES     93  
 
PART IV
15.
  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES     93  
 EX-10.6
 EX-10.11
 EX-21.1
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-99.1


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CROSSTEX ENERGY, L.P.
 
PART I
 
Item 1.   Business
 
General
 
Crosstex Energy, L.P. is a publicly traded Delaware limited partnership. Our Common Units are listed on the NASDAQ Global Select Market under the symbol “XTEX”. Our business activities are conducted through our subsidiary, Crosstex Energy Services, L.P., a Delaware limited partnership (the “Operating Partnership”) and the subsidiaries of the Operating Partnership. Our executive offices are located at 2501 Cedar Springs, Dallas, Texas 75201, and our telephone number is (214) 953-9500. Our Internet address is www.crosstexenergy.com. In the “Investors” section of our web site, we post the following filings as soon as reasonably practicable after they are electronically filed with or furnished to the Securities and Exchange Commission: our annual report on Form 10-K; our quarterly reports on Form 10-Q; our current reports on Form 8-K; and any amendments to those reports or statements filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. All such filings on our web site are available free of charge. In this report, the terms “Partnership” and “Registrant,” as well as the terms “our,” “we,” “us” and “its,” are sometimes used as abbreviated references to Crosstex Energy, L.P. itself or Crosstex Energy, L.P. together with its consolidated subsidiaries, including the Operating Partnership.
 
We are an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids, or NGLs. We connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities to ensure that it meets pipeline quality specifications, process natural gas for the removal of NGLs, fractionate NGLs into purity products and market those products for a fee, transport natural gas and ultimately provide natural gas to a variety of markets. We purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipelines. We operate processing plants that process gas transported to the plants by major interstate pipelines or from our own gathering systems under a variety of fee arrangements. In addition, we purchase natural gas from producers not connected to our gathering systems for resale and sell natural gas on behalf of producers for a fee.
 
We have two operating segments, Midstream and Treating. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and NGLs, while our Treating division focuses on the removal of impurities from natural gas to meet pipeline quality specifications. Our primary Midstream assets include over 5,700 miles of natural gas gathering and transmission pipelines, 12 natural gas processing plants and four 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 primary Treating assets include approximately 225 natural gas amine-treating plants and 56 dew point control plants. Our natural gas treating plants remove carbon dioxide and hydrogen sulfide from natural gas prior to delivering the gas into pipelines to ensure that it meets pipeline quality specifications. See Note 17 to the consolidated financial statements for financial information about these operating segments.


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Set forth in the table below is a list of our acquisitions since January 1, 2004.
 
                 
Acquisition
  Acquisition Date   Purchase Price    
Asset Type
        (In thousands)      
 
LIG Acquisition
  April 2004     73,692     Gathering and transmission systems and processing plants
Crosstex Pipeline Partners
  December 2004     5,100     Gathering pipeline
Graco Operations
  January 2005     9,257     Treating plants
Cardinal Gas Services
  May 2005     6,710     Treating plants and gas processing plants
El Paso Acquisition
  November 2005     480,976     Processing and liquids business (including 23.85% interest in Blue Water gas processing plant)
Hanover Amine Treating
  February 2006     51,700     Treating plants
Blue Water Acquisition
  May 2006     16,454     Additional 35.42% interest in gas processing plant
Chief Acquisition
  June 2006     475,287     Gathering and transmission systems and carbon dioxide treating plant
Cardinal Gas Solutions
  October 2006     6,330     Dew point control plants and treating plants
 
Our general partner interest is held by Crosstex Energy GP, L.P., a Delaware limited partnership. Crosstex Energy GP, LLC, a Delaware limited liability company, is Crosstex Energy GP, L.P.’s general partner. Crosstex Energy GP, LLC manages our operations and activities and employs our officers. Crosstex Energy GP, L.P. and Crosstex Energy GP, LLC are indirect, wholly-owned subsidiaries of Crosstex Energy, Inc., or CEI.
 
As generally used in the energy industry and in this document, the following terms have the following meanings:
 
      /d = per day
Bbls = barrels
Bcf = billion cubic feet
Btu = British thermal units
Mcf = thousand cubic feet
MMBtu = million British thermal units
MMcf = million cubic feet
NGL = natural gas liquid
 
Capacity volumes for our facilities are measured based on physical volume and stated in cubic feet (Bcf, Mcf or MMcf). Throughput volumes are measured based on energy content and stated in British thermal units (Btu or MMBtu). A volume capacity of 100 MMcf generally correlates to volume throughput of 100,000 MMBtu.
 
Recent Developments
 
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Numerous events during 2008 have severely restricted current liquidity in the capital markets throughout the United States and around the world. The ability to raise money in the debt and equity markets has diminished significantly and, if available, the cost of funds has increased substantially. One of the features driving investments in master limited partnerships (“MLPs”) , including the Partnership, over the past few years has been the distribution growth offered by MLPs due to liquidity in the financial markets for capital investments to grow distributable cash flow through development projects and acquisitions. Future growth opportunities have been and are expected to continue to be constrained by the lack of liquidity in the financial markets.
 
In addition, our business has been significantly impacted by the substantial decline in crude oil prices during the last half of 2008 from a high of approximately $145 per Bbl in July 2008 to a low of approximately $34 per Bbl in December 2008 (based on NYMEX futures daily close prices for the prompt month), a 76.7% decline, and the


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related 78.2% decline in NGL prices from a high of $2.19 per gallon in July 2008 to a low of $0.48 per gallon in December 2008 (based on the OPIS Mt. Belvieu daily average spot liquids prices). Crude oil prices reflected on NYMEX during January and February 2009 have fluctuated, to a lesser extent, between $49 per Bbl and $35 per Bbl while the OPIS Mt. Belvieu NGL prices have improved slightly ranging from $0.81 per gallon and $0.62 per gallon. The declines in NGL prices have negatively impacted our gross margin for the fourth quarter of 2008 and could continue to negatively impact our gross margin (revenue less cost of gas purchases) in 2009. A significant percentage of inlet gas at our processing plants is settled under percent of liquids (“POL”) agreements or fractionation margin (margin) contracts. Over the past two years the inlet processing volumes associated with POL and margin contracts were approximately 70%, on a combined basis, of the total volume of gas processed. The POL fees are denominated in the form of a share of the liquids extracted. Therefore, fee revenue under a POL agreement is directly impacted by NGL prices and the decline of these prices in 2008 contributed to a significant decline in gross margin from processing. Under the POL settlement terms, we are not responsible for the fuel or shrink associated with processing. Under margin contracts we realize a gross margin from processing based upon the difference in the value of NGLs extracted from the gas less the value of the product in its gaseous state and the cost of fuel to extract. This is often referred to as the “fractionation spread”. During the last half of 2008 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 also negatively impacted due to the commodity price environment. If the current weakness in the economy continues for a prolonged period, it would likely further reduce demand for gas and for NGL products, such as ethane, a primary feedstock for the petrochemical and manufacturing industries, and result in continued lower natural gas and NGL prices. Although we have seen some improvement in NGL prices and the fractionation spread in the early months of 2009 over the levels experienced in December 2008, we believe that our processing margins in 2009 will be substantially lower than the processing margins realized in 2008 based on current market indicators. For the year ended December 31, 2008, approximately 38.7% of our gross margin was attributable to gas processing as compared to 46.1% of our gross margin for the year ended December 31, 2007. See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk” for a description of our contractual processing arrangements.
 
Natural gas prices have declined by approximately 61.0%, from a high of $13.58 per MMBtu in July 2008 to a low of $5.29 per MMBtu in December 2008 (based on NYMEX futures daily close prices for the prompt month). Natural gas prices have declined even further during January and February 2009 with prices ranging from $6.07 in early January to $4.01 in mid-February. Many of our customers finance their drilling activity with cash flow from operations, which have been negatively impacted by the declines in natural gas and crude oil prices, or through the incurrence of debt or issuance of equity, which markets have been adversely impacted by global financial market conditions. We believe that the adverse price changes coupled with the overall downturn in the economy and the constrained capital markets will put downward pressure on drilling budgets for gas producers which could result in lower volumes being transported on our pipeline and gathering systems and processed through our processing plants. We have seen a decline in drilling activity by gas producers in our areas of operation during the fourth quarter of 2008. In addition, industry drilling rig count surveys published in early 2009 show substantial declines in rigs in operation as compared to 2008. Several of our customers, including one of our largest customers in the Barnett Shale, have recently announced drilling plans for 2009 that are substantially below their drilling levels during 2008.
 
Our business was also negatively impacted by hurricanes Gustav and Ike, which came ashore in the Gulf Coast in September 2008. Although the majority of our assets in Texas and Louisiana sustained minimal physical damage from these hurricanes and promptly resumed operations, several offshore production platforms and pipelines 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 we do not anticipate that gas production to our south Louisiana plants will recover to pre-hurricane levels until mid-2009, when all repairs are expected to be complete. Additionally, one of our south Louisiana processing plants, the Sabine Pass processing plant, which is located on the shoreline of the Louisiana Gulf Coast, sustained some physical damage. The Sabine Pass processing plant was repaired during the fourth quarter of 2008 and the plant was returned to service in early January 2009. Our operations in north Texas were also impacted by these hurricanes because operations at Mt. Belvieu, Texas, a central distribution point for NGL sales where several fractionators are located which fractionate NGLs from the entire United States, were interrupted as a


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result of these storms. These storms resulted in an adverse impact to our gross margin of approximately $22.9 million.
 
Two of our facilities, one in south Louisiana and one in north Texas, were also partially damaged by fires during 2008. Although substantially all of the property repairs were covered by insurance, our Sabine Pass processing plant in south Louisiana was out of service for approximately one month. The loss of operating income due to the fire at the Godley compressor station in north Texas was minimal because we were successful in rerouting the gas to our other facilities in the area until the damaged compressor was replaced. The estimated loss in gross margin as a result of these fires was $0.9 million.
 
Business Strategy
 
Until the occurrence of the recent developments described above, our long-term strategy has 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 these recent events, we adjusted our business strategy in the fourth quarter 2008 and for 2009 to focus on maximizing our liquidity, maintaining a stable asset base, improving the profitability of our assets by increasing their utilization while controlling costs and reducing our capital expenditures by undertaking the following steps:
 
  •  We intend to operate our existing asset base to enhance profitability by undertaking 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, including midstream and treating 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 and eastern Texas.
 
  •  We amended our bank credit facility and our senior secured note agreements in November 2008 and again in February 2009 to negotiate terms that facilitate our compliance with debt covenants while we operate our assets during the current difficult economic conditions. The terms of the amended agreements allow us to maintain a higher level of leverage and to maintain a lower interest coverage ratio; however, our interest costs will increase and our ability to pay distributions and incur additional indebtedness will be restricted when we are operating at higher leverage ratios. The terms of these agreements are described more fully under “Amendments to Credit Documents” below and in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
  •  We have lowered our distribution level from $0.63 per unit for the second quarter of 2008 to $0.25 per unit for the fourth quarter of 2008. The amended terms of our credit facility and senior secured note agreement prohibit us from making distributions unless our leverage ratio is below certain levels and the PIK notes have been repaid as discussed more fully under “Amendments to Credit Documents.” We do not expect that we will meet these conditions in 2009.
 
  •  We sold certain non-strategic assets in November 2008 and used the proceeds from such sales to reduce our outstanding borrowings under our bank credit facility. We received $85.0 million for the sale of our 12.4% interest in the Seminole gas processing plant to an unaffiliated third party and we received $20.0 million for the assignment of a transportation contract right to another unaffiliated third party. We may consider selling other non-strategic assets during 2009 and use the proceeds to further reduce our indebtedness if we are able to obtain attractive offers for such assets.
 
  •  We have reduced our budgeted capital expenditures significantly for 2009. Total growth capital investments in the calendar year 2009 are currently anticipated to be approximately $100.0 million and primarily relate to capital projects in north Texas and Louisiana pursuant to contract obligations with producers. Our ability to grow our asset base through the continued development of our north Texas and Louisiana assets or through acquisitions will be limited due to our lack of access to capital markets and due to restrictions under our debt agreements. We will use cash flow from operations and existing capacity under our bank credit facility to fund our reduced capital spending plan during 2009. Capital expenditures in future periods will be limited to cash flow from operating activities and to existing capacity under our bank credit facility.


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  •  We have reduced our general and administrative expenses by reducing our work force by approximately 8.0% through the elimination of open positions and certain corporate positions and minimizing all non-essential costs. We have also reduced our operating expenses by reducing overtime and renegotiating certain contracts to reduce monthly costs and by eliminating certain equipment rentals.
 
Amendments to Credit Documents
 
On November 7, 2008, we amended our bank credit facility and senior secured note agreement to, among other things, revise the leverage ratio and interest coverage ratio requirements to ease the covenant restrictions under the agreements and to permit us to sell certain assets, including the non-strategic asset dispositions described in “Business Strategy” above. The amendments also included provisions that increased the interest rates under both our bank credit facility and our senior note agreement by 1.25% per annum and increased the other fees associated with our bank credit facility.
 
Due to the continued decline in commodity prices and the deterioration in processing margins, we determined that there was a significant risk that the amended terms negotiated in November would not be sufficient to allow us to operate during 2009 without triggering a covenant default under our bank facility and the senior secured note agreement. On February 27, 2009, we amended our bank credit facility and the senior secured note agreement to include revised terms that facilitate our compliance with debt covenants while we operate our assets during the current difficult economic conditions. In general terms, the amended agreement allows us to maintain a higher level of leverage and to maintain a lower interest coverage ratio; however, our interest costs will increase, our ability to incur additional indebtedness will be restricted when we are operating at higher leverage ratios and our ability to pay distributions will be prohibited until our leverage ratio is significantly lower and we repay the PIK notes (as defined below).
 
Under the amended bank credit facility, if we are operating at higher leverage ratios, our interest margin over the London Interbank Offering Rate (“LIBOR”) on our LIBOR borrowings will generally increase to 4.00% per annum, which represents an increase of 2.25% over the comparative interest rate under the credit agreement prior to the November and February amendments. The fees charged for letters of credit will also increase by 2.25%. The interest margin on our LIBOR borrowings will decline from the maximum level of 4.00% to a low of 2.75% when our leverage ratios are at the lower end of the range. The amendment also sets a floor for the LIBOR interest rate of 2.75% per annum, which means, effective as of February 27, 2009, borrowings under the bank credit facility accrue interest at the rate of 6.75% based on the LIBOR rate in effect on such date and our current leverage ratio. The interest rates and leverage ratios under the amended agreement are described more fully in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Indebtedness.”
 
Commencing February 27, 2009 the interest rate we pay on all of the senior secured notes will increase by 2.25% per annum over the comparative interest rates under the senior note agreement prior to the November and February amendments. As a result of this rate increase, the weighted average cash interest rate on the outstanding balance on the senior secured notes is approximately 9.25% as of February 2009.
 
Under the amended senior note agreement, the senior secured notes will accrue additional interest of 1.25% in the form of an increase in the principal amount of the senior secured notes (the “PIK notes”) unless our leverage ratio is less than 4.25 to 1.00 as of the end of any fiscal quarter. All PIK interest will be payable 180 days after the maturity of the bank credit facility.
 
Per the terms of the amended senior secured note agreement, commencing on the date we refinance our bank credit facility, the interest rate payable in cash on our senior secured notes will increase by 1.25% per annum for any quarter if our leverage ratio as of the most recently ended fiscal quarter was greater than or equal to 4.25 to 1.00. In addition, commencing on June 30, 2012, the interest rate payable in cash on our senior secured notes will increase by 0.50% per annum for any quarter if our leverage as of the most recently ended fiscal quarter was greater than or equal to 4.00 to 1.00, but this incremental interest will not accrue if we are paying the incremental 1.25% per annum of interest described in the preceding sentence.
 
Under our amended bank credit facility and senior secured note agreement, we must pay a leverage fee if we do not prepay debt and permanently reduce the banks’ commitments by the cumulative amounts of $100.0 million on


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September 30, 2009, $200.0 million on December 31, 2009 and $300.0 million on March 31, 2010. If we fail to meet any de-leveraging target, we must pay a leverage fee on such date, equal to the product of the aggregate commitment outstanding under our bank credit facility and the outstanding amounts of senior secured note agreement on such date, and 1.0% on September 30, 2009, 1.0% on December 31, 2009, and 2.0% on March 31, 2010. This leverage fee will accrue on the applicable date, but not be payable until we refinance our bank credit facility.
 
Under our amended bank credit facility and senior secured note agreement, we may not make quarterly distributions to our unitholders unless the PIK notes have been repaid and the leverage ratio, as defined in the agreements, is less than 4.25 to 1.00. If the leverage ratio is between 4.00 to 1.00 and 4.25 to 1.00, we may make the minimum quarterly distributions of up to $0.25 per unit if the PIK notes have been repaid. If the leverage ratio is less than 4.00 to 1.00, we may make quarterly distributions to unitholders from available cash as provided by our partnership agreement if the PIK notes have been repaid. The PIK notes are due six months after the earlier of the refinancing or maturity of our bank credit facility. Based on our forecasted leverage ratios for 2009, we do not anticipate making quarterly distributions in 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results. We will not be able to make distributions to our unitholders in future periods if our leverage ratio does not improve and the PIK notes are not first repaid.
 
Our amended credit facility and senior secured note agreement also limit our annual capital expenditures (excluding maintenance capital expenditures) to $120.0 million in 2009 and $75.0 million in 2010 and in each year thereafter (with unused amounts in any year being carried forward to the next year). It is unlikely that we will be able to make any acquisitions based on the terms of our credit facility and the current condition of the capital markets because, as discussed below, we may only use a portion of the proceeds from the incurrence of unsecured debt and the issuance of equity to make such acquisitions.
 
Our amended credit facility and senior secured note agreement also require us to repay outstanding indebtedness from proceeds from asset sales and debt and equity issuances. All proceeds from asset sales must be used to prepay indebtedness. All proceeds from the incurrence of unsecured debt and 50% of the proceeds from equity issuances must be used to prepay indebtedness if our leverage ratio exceeds 4.50 to 1.00. If our leverage ratio is less than 4.50 to 1.00 but greater than 3.50 to 1.00, 50% of the debt proceeds and 25% of the equity proceeds must be used to prepay indebtedness. If our leverage ratio is less than 3.50 to 1.00, there are no prepayment requirements from debt and equity issuances. The prepayments are to be applied pro rata based on total debt (including letter of credit obligations) outstanding under the bank credit agreement and the total debt outstanding under the note agreements described below. Any prepayments of advances on the bank credit facility from proceeds from asset sales, debt or equity issuances will permanently reduce the borrowing capacity or commitment under the facility in an amount equal to 100% of the amount of the prepayment. Any such commitment reduction will not reduce the banks’ $300.0 million commitment to issue letters of credit under our bank facility.
 
We were in compliance with all debt covenants at December 31, 2008 and 2007 and expect to be in compliance with debt covenants for the next twelve months.
 
For more information on the amendments to our bank credit facility and senior secured note agreement, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Indebtedness.”
 
Acquisitions and Expansion in Recent Years
 
North Texas Assets.  Our North Texas Pipeline, or NTP, which commenced service in April 2006, consists of a 133-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 and other markets. As of December 2008, the total throughput on the NTP was approximately 300,000 MMBtu/d. The NTP also will interconnect with a new interstate gas pipeline under construction by Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing Pipeline, which is expected to be in service in March 2009. The Gulf Crossing Pipeline is expected to provide our customers access to premium midwest and east coast markets.


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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 Holdings, LLC, or Chief, in the Barnett Shale for $475.3 million. The acquired systems, which we refer to in conjunction with the NTP and our other facilities in the area as our North Texas Assets, included gathering pipeline, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that acquisition, approximately 160,000 net acres previously owned by Chief and acquired by Devon Energy Corporation, or 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 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 2007 and 2008 and will continue to be a core area during 2009. Since the date of the acquisition through December 31, 2008, we have connected 444 new wells to our gathering system and significantly increased the dedicated acreage owned by other producers. Our processing capacity in the Barnett Shale is 280 MMcf/d including the 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. In 2007 and 2008, we constructed a 29-mile expansion in north Johnson County to our north Texas gathering systems. The first phase of the expansion commenced operation in September 2007. The last two phases of the expansion commenced operation in May and July of 2008. The total gathering capacity of this 29-mile expansion is currently 235 MMcf/d and is expected to be increased to approximately 400 MMcf/d in April 2009 by the addition of compression. We have also installed two 40 gallon per minute and one 100 gallon per minute amine treating plants to provide carbon dioxide removal capability. As of December 2008, the capacity of our north Texas gathering system was approximately 1,100 MMcf/d and total throughput on our north Texas gathering systems, including the north Johnson County expansion, had increased from approximately 115,000 MMBtu/d at the time of the Chief acquisition to approximately 796,000 MMBtu/d.
 
In April 2008, we commenced construction of an $80.0 million natural gas processing facility called Bear Creek in Hood County near our existing North Texas Assets. The new plant will have a gas processing capacity of 200 MMcf/d. Due to the recent decline in commodity prices and the corresponding decline in drilling activity, we do not anticipate that the additional processing capacity provided by the Bear Creek plant will be needed until late 2010 or in 2011. Therefore, we have decided to put this construction project on hold until the demand for this processing capacity returns, at which time we will seek to obtain financing for this project. As of December 31, 2008, we have spent approximately $20.2 million on this project for construction of a portion of the plant that will be utilized when the plant is completed in the future.
 
We have budgeted approximately $57.0 million for continued development of our north Texas assets during 2009. 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. Several of our customers, including one of our largest customers in the Barnett Shale, have recently announced drilling plans for 2009 that are substantially below their drilling levels during 2008. As a result, our capital expenditures related to well connections during 2009 may be less than budgeted.
 
North Louisiana Expansion Project.  In April 2007, we completed construction and commenced operations on our north Louisiana expansion, which is an extension of our LIG system designed to increase take-away pipeline capacity to the producers developing natural gas in the fields south of Shreveport, Louisiana. The north Louisiana expansion consists of approximately 63 miles of 24” mainline with 9 miles of 16” gathering lateral pipeline and 10,000 horsepower of new compression referred to as our Red River lateral. Our Red River lateral bisects the developing Haynesville Shale gas play in north Louisiana. The Red River lateral was operating at near capacity during 2008 so we added 35 MMcf/d of capacity by adding compression during the third quarter of 2008, bringing the total capacity of the Red River lateral to approximately 275 MMcf/d. As of December 31, 2008, the Red River lateral was flowing at approximately 225,000 MMBtu/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission and Trunkline Gas.
 
We have budgeted approximately $31.0 million for continued expansion in north Louisiana during 2009 with additional compression providing approximately 100 MMcf/d of increased capacity to producers in the Haynesville


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Shale gas play. The expansion is scheduled to be completed in July 2009. We have 10 year firm transportation contracts subscribing to all the capacity on this project with four large producers.
 
Other Developments
 
Issuance 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. Net proceeds from the issuance, including the general partner contribution less expenses associated with the issuance, were approximately $102.0 million.
 
Conversion of Subordinated and Senior Subordinated Series C Units.  The subordination period for the subordinated units owned by our general partner ended and the remaining 4,668,000 subordinated units converted into common units representing limited partner interests of the Partnership effective February 16, 2008.
 
The 12,829,650 senior subordinated series C units also converted into common units representing limited partner interests effective February 16, 2008. Our general partner owned 6,414,830 of the series C units that converted to common units.
 
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. The senior subordinated series D units will convert to common units representing limited partner interests on March 23, 2009. Since we did not make distributions of available cash from operating surplus, as defined in the partnership agreement, of at least $0.62 per unit on each outstanding common unit for the quarter ending December 31, 2008 and did not generate adjusted operating surplus, as defined in the partnership agreement, of at least $0.62 per unit on each outstanding common unit for the quarter ending December 31, 2008, each senior subordinated series D unit will convert into 1.05 common units.
 
Midstream Segment
 
Gathering, Processing and Transmission.  Our primary Midstream assets include our North Texas Assets, south Texas assets, Louisiana assets and Mississippi assets. These systems, in the aggregate, consist of over 5,700 miles of pipeline, 12 natural gas processing plants and four fractionators and contributed approximately 88.0% of our gross margin in both 2008 and 2007.
 
  •  North Texas Assets.  On June 29, 2006, we acquired the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale. The acquired systems included gathering pipeline, 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 pipeline gathering system.
 
  •  Gathering System.  Since the date of the acquisition through December 31, 2008, we have connected 444 new wells to our north Texas gathering system and significantly increased the dedicated acreage owned by other producers. During May and July 2008, we completed the 29-mile expansion in north Johnson County to our north Texas gathering systems with a current gathering capacity of 235 MMcf/d which will be increased to 400 MMcf/d in April 2009 by adding compression. As of December 31, 2008, total capacity on our north Texas gathering system, including the north Johnson County expansion, was approximately 1,100 MMcf/d and total throughput was approximately 796,000 MMBtu/d.
 
  •  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. We have also installed two 40 gallon per minute and one 100 gallon per minute amine treating plants to provide carbon dioxide removal capability.


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  •  North Texas Pipeline (NTP).  We expanded our NTP system in the second quarter of 2007 to a total capacity of approximately 375 MMcf/d. The NTP will also interconnect with a new interstate pipeline that is being constructed by Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing Pipeline, which is expected to provide our customers access to premium midwest and east coast markets.
 
  •  South Texas Assets.  We have assembled a highly-integrated south Texas system comprised of approximately 1,400 miles of intrastate gathering and transmission pipelines, processing plants with a processing capacity of approximately 150 MMcf/d and a contract with a third party to process gas from our Vanderbilt system. The south Texas system was built through a number of acquisitions and follow-on organic projects, including acquisitions of the Gulf Coast system, the Corpus Christi system, the Gregory gathering system and processing plant, the Hallmark system and the Vanderbilt system. Average throughput on the system for the year ended December 31, 2008 was approximately 423,000 MMBtu/d, and average throughput for the Gregory and Vanderbilt processing assets was approximately 187,000 MMBtu/d. The system gathers gas from major production areas in the Texas Gulf Coast and delivers gas to the industrial markets, power plants, other pipelines and gas distribution companies in the region from Corpus Christi to the Houston area.
 
  •  Louisiana Assets.  Our Louisiana assets include our LIG intrastate pipeline system and our gas processing and liquids business in south Louisiana, referred to as our south Louisiana processing assets.
 
  •  LIG System.  The LIG system is the largest intrastate pipeline system in Louisiana, consisting of approximately 2,000 miles of gathering and transmission pipeline, with an average throughput of approximately 960,000 MMBtu/d for the year ended December 31, 2008. The system also includes two operating, on-system processing plants, our Plaquemine and Gibson plants, with an average throughput of 311,000 MMBtu/d for the year ended December 31, 2008. 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. 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 LIG system to the north to reach additional productive areas. This extension, referred to as the north Louisiana expansion or Red River lateral, consists of 63 miles of 24” mainline with 9 miles of gathering lateral pipeline and 10,000 horsepower of compression. Our Red River lateral bisects the developing Haynesville Shale gas play in north Louisiana. The Red River lateral was operating at near capacity during 2008 so we added 35 MMcf/d of capacity by adding compression during the third quarter of 2008 bringing the total capacity of the Red River lateral to approximately 275 MMcf/d. As of December 31, 2008, the Red River lateral was flowing at approximately 225,000 MMBtu/d.
 
  •  South Louisiana Processing Assets.  Natural gas processing capacity available to the Gulf Coast producers continues to exceed demand. During 2007 and 2008, 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 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. Most of the south Louisiana assets, other than the Sabine Pass processing plant, sustained minimal physical damage and promptly resumed operations. The repairs to the Sabine Pass processing plant were completed during the fourth quarter of 2008 and the plant returned to service in January 2009. In addition, 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 and repair to these offshore facilities continued during the fourth quarter of 2008. We anticipate that production levels will not recover to pre-hurricane levels until mid-2009, when all repairs are expected to be complete. The south Louisiana processing assets include the following:
 
  •  Eunice Processing Plant and Fractionation Facility.  The Eunice processing plant has a capacity of 1.2 Bcf/d and processed approximately 521,000 MMBtu/d for the year ended December 31, 2008. The plant is connected to onshore gas supply, as well as continental shelf and deepwater gas production and


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  has downstream connections to the ANR Pipeline, Florida Gas Transmission and Texas Gas Transmission, or TGT. TGT modified its system operations in early 2007 in a manner that significantly reduced the volumes available from TGT for processing at the Eunice plant. The Eunice fractionation facility, which was idled in August 2007, has a capacity of 36,000 Bbls/d 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. If liquid volumes exceed Riverside’s fractionation capacity, the liquids are delivered to a third party for fractionation. This operational change improved overall operating income because of operating cost reductions at the Eunice plant. The facility continues to maintain a truck unloading rack where approximately 10 trucks per day are unloaded and the raw make is sent to Riverside for fractionation. Eunice also has 190,000 Bbls of above-ground storage capacity. 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.
 
  •  Pelican Processing Plant.  The Pelican processing plant complex is located in Patterson, Louisiana and has a capacity of 600 MMcf/d of natural gas. For the year ended December 31, 2008, the plant processed approximately 266,000 MMBtu/d. The Pelican plant is connected with continental shelf and deepwater production and has downstream connections to the ANR Pipeline.
 
  •  Sabine Pass Processing Plant.  The Sabine Pass processing plant is located east of the Sabine River at Johnson’s Bayou, Louisiana and has a capacity of 300 MMcf/d of natural gas. The Sabine Pass processing plant is connected to continental shelf and deepwater gas production with downstream connections to Florida Gas Transmission, Tennessee Gas Pipeline (TGP) and Transco. For the first seven months of 2008, this facility was processing at full capacity. In early August 2008, the Sabine Pass processing plant sustained fire damage which occurred during an attempt to bring the plant back on line following a tropical storm. The plant was repaired and ready to return to service when it was hit by hurricanes Gustav and Ike in early September 2008. The plant has been repaired and was placed back in service in early January 2009.
 
  •  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. For the year ended December 31, 2008, this facility processed approximately 110,000 MMBtu/d net to our interest. The Blue Water plant is located near Crowley, Louisiana. The Blue Water facility is connected to continental shelf and deepwater production volumes through the Blue Water pipeline system. The facility also performs liquid natural gas (LNG) conditioning services for the Excelerate Energy LNG tanker unloading facility. Downstream connections from this plant include TGP and Columbia Gulf Transmission. 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 is not currently in operation. At this time, we have not found alternative sources of new gas for the Blue Water plant but we will continue to look for new sources of gas, including the option of moving gas from our LIG system over to Blue Water plant. We do not expect to make a decision on any of these options for the Blue Water plant in the near term due to the excess processing capacity in the Gulf Coast and our restricted access to capital. The Blue Water plant contributed gross margin of $3.9 million and $4.2 million and incurred operating expenses of $1.2 million and $1.1 million for the years ended December 31, 2008 and 2007, respectively. We recognized an impairment of $17.8 million for the year ended December 31, 2008 related to the Blue Water plant because the plant was idled in January 2009. This impairment represents the carrying amount of the plant in excess of the estimated fair value of the plant as of December 31, 2008.
 
  •  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 28,000 to 30,000 Bbls/d of liquids products and fractionates liquids delivered by the Cajun Sibon


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  pipeline system from our Eunice, Pelican, Blue Water and Cow Island plants or by truck. The Riverside facility has above-ground storage capacity of approximately 102,000 Bbls.
 
  •  Napoleonville Storage Facility.  The Napoleonville NGL storage facility is connected to the Riverside facility and has a total capacity of approximately 2.4 million Bbls of underground storage.
 
  •  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 the Napoleonville storage facility. Alternate deliveries can be made to the Eunice plant.
 
  •  Mississippi Assets.  Our Mississippi assets include approximately 600 miles of natural gas gathering and transmission pipelines. The system gathers natural gas from producers, receives and delivers natural gas from and to several major interstate pipelines, including Sonat and Transco, and delivers gas to utilities and industrial end-users. The average system throughput was approximately 128,000 MMBtu/d for the year ended December 31, 2008.
 
  •  Other Midstream assets and activities include:
 
  •  Arkoma Gathering System.  This approximately 140 mile low-pressure gathering system in southeastern Oklahoma delivers gathered gas into a mainline transmission system. For the year ended December 31, 2008, throughput on the system averaged approximately 22,000 MMBtu/d. This gathering system was sold in February 2009 to an unrelated third party for approximately $11.0 million.
 
  •  East Texas.  Currently our east Texas system, made up of natural gas pipelines and compression installations, gathers and processes natural gas and delivers gas to NGPL, Regency Gas, and to other intrastate pipeline systems. For the year ended December 31, 2008, throughput on the system averaged approximately 42,000 MMBtu/d. We expanded this gas gathering system in May 2008 and it has a current capacity of 100 MMcf/d. We are expecting to receive our first delivery of Haynesville Shale gas into our east Texas system in the first quarter of 2009.
 
  •  Other.  Other Midstream assets consist of a variety of gathering lines and processing plants with a processing capacity of approximately 66 MMcf/d. Total volumes gathered and resold were approximately 16,000 MMBtu/d for the year ended December 31, 2008. Total volumes processed were approximately 16,000 MMBtu/d in the same period.
 
  •  Off-System Services.  We offer natural gas marketing services on behalf of producers of natural gas that is not gathered, transmitted, treated or processed by our assets. We market this gas on a number of interstate and intrastate pipelines. These volumes averaged approximately 85,000 MMBtu/d in 2008.
 
Treating Segment
 
We operate (or lease to producers for operation) treating plants that remove carbon dioxide and hydrogen sulfide from natural gas before it is delivered into transportation systems to ensure that it meets pipeline quality specifications. Our treating division contributed approximately 12.0% of our gross margin in both 2008 and 2007. At December 31, 2008, we had approximately 200 treating and dew point control plants in operation. Pipeline companies have begun enforcing gas quality specifications to lower the dew point of the gas they receive and transport. A higher relative dew point can sometimes cause liquid hydrocarbons to condense in the pipeline and cause operating problems and gas quality issues to the downstream markets. Hydrocarbon dew point plants are skid mounted process equipment that remove these hydrocarbons. Typically these plants use a Joules-Thompson expansion process to lower the temperature of the gas stream and collect the liquids before they enter the downstream pipeline. Our Treating division views dew point control as complementary to our treating business.
 
We believe we have the largest gas treating operation in the Texas and Louisiana gulf coast. Natural gas from certain formations in the Texas gulf coast, as well as other locations, is high in carbon dioxide, which generally needs to be removed before introduction of the gas into transportation pipelines. Many of our active plants are treating gas from the Wilcox and Edwards formations in the Texas gulf coast, both of which are deeper formations


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that are high in carbon dioxide. In cases where producers pay us to operate the treating facilities, we either charge a fixed rate per Mcf of natural gas treated or charge a fixed monthly fee.
 
All of the shale reservoirs being developed today have concentrations of carbon dioxide above the normal pipeline quality specifications of 2.0%. The Haynesville Shale in northern Louisiana is still experiencing some robust development because of the higher success in completing these wells. We believe that our Treating business strategy is well suited to the producers in the Haynesville Shale especially during this time of relatively lower gas prices. The lower gas prices create an incentive for producers to use equipment supplied by others as opposed to buying their own equipment because it is more efficient use of their capital.
 
Our treating growth strategy is to utilize our existing fleet of amine plants to support our growth in the Haynesville Shale gas play. We believe our track record of reliability, current availability of equipment and our strategy of sourcing new equipment provide a significant advantage in competing for new treating business.
 
Treating process.  The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to remove the impurities from the gas. After mixing, gas and reacted amine are separated and the impurities are removed from the amine by heating. Treating plants are sized by the amine circulation capacity in terms of gallons per minute.
 
Sale of Interest in the Seminole Plant.  In November 2008, we sold our undivided 12.4% interest in the Seminole gas processing plant to an unrelated third party for $85.0 million and realized a gain on the sale of $49.8 million. We acquired our non-operating interest in this carbon dioxide processing plant in June 2003.
 
Industry Overview
 
The following diagram illustrates the natural gas treating, 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-use 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


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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 treating.  The composition of natural gas varies depending on the field the formation and reservoir from which it is produced. Natural gas from certain formations is high in carbon dioxide. Treating plants are placed at or near a well and remove carbon dioxide and hydrogen sulfide from natural gas before it is introduced into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications.
 
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 must 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 facilitates 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.
 
Supply/Demand Balancing
 
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 New York Mercantile Exchange. 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 future contracts or derivative products for the purpose of speculating on price changes.
 
Competition
 
The business of providing gathering, transmission, treating, 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


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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.
 
Our gas treating operations face competition from manufacturers of new treating and dew point control plants and from a small number of regional operators that provide plants and operations similar to ours. We also face competition from vendors of used equipment that occasionally operate plants for producers. In addition, we routinely lose business to gas gatherers who have underutilized treating or processing capacity and can take the producers’ gas without requiring wellhead treating. We may also lose wellhead treating opportunities to blending, which is a pipeline company’s ability to waive quality specifications and allow producers to deliver their contaminated gas untreated. This is generally referred to as blending because of the receiving company’s ability to blend this gas with cleaner gas in the pipeline such that the resulting gas meets pipeline specification.
 
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, 2008, we had one customer that accounted for approximately 11.0% of our consolidated revenues. 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 some 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. Rates for interstate services provided under NGPA Section 311 on our NTP and Mississippi systems are currently under review. The filed rates, which are based on the respective system’s cost of service and constitute the maximum rates that can be charged on those systems for interstate service, are slightly lower than the rates previously charged. Rate reviews on our Louisiana and south Texas pipeline systems are scheduled for March and April 2009, respectively.
 
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. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect less extensive regulation. 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 treating, processing and fractionation plants, pipelines and associated facilities in connection with the gathering, treating 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


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


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statutes. We are not currently required to comply with a substantial portion of the FRCRA requirements because our operations generate minimal quantities of hazardous wastes. From time to time, the Environmental Protection Agency, or EPA, has considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated by 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 regulations may result in an increase in our capital expenditures or plant operating expenses.
 
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, FRCRA, 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.
 
We acquired our south Louisiana processing assets from El Paso in November 2005. One of the acquired locations, the Cow Island Gas Processing Facility, has a known active remediation project for benzene contaminated groundwater. The cause of contamination was attributed to a leaking natural gas condensate storage tank. The site investigation and active remediation being conducted at this location is under the guidance of the Louisiana Department of Environmental Quality (LDEQ) based on the Risk-Evaluation and Corrective Action Plan Program (RECAP) rules. We have completed the remediation work on this site pending the final review and approval of our reports by LDEQ. As of December 31, 2008, we had incurred approximately $0.5 million in such remediation costs. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to our ownership, these costs were accrued as part of the purchase price.
 
We acquired LIG Pipeline Company, and its subsidiaries, on April 1, 2004 from American Electric Power Company (AEP). Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. AEP has indemnified us for these identified sites. Moreover, AEP has entered into an agreement with a third party company pursuant to which the remediation costs associated with these sites have been assumed by this third party company that specializes in remediation work. This remediation work is nearing completion. We do not expect to incur any material liability associated with this site; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.
 
We acquired assets from Duke Energy Field Services, L.P. (DEFS) in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, contamination from historical operations had been identified at levels that exceeded the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million. Under the purchase and sale agreement, DEFS retained the liability for cleanup of the Conroe site. Moreover, DEFS has entered into an agreement with a third party company pursuant to which the remediation costs associated with the Conroe site have been assumed by this third party company that specializes in remediation work. We do not expect to incur any material liability associated with this site; however, there can be no assurance that the third parties who have assumed responsibility for remediation of site conditions will fulfill their obligations.
 
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


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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.
 
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. The EPA is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act. 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.
 
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


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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.
 
During 2008 the Partnership leased approximately 115,000 square feet of additional office space at 2828 N. Harwood Street, Dallas, Texas. This space was intended to accommodate the corporate office expansion required by the continued growth of the business. Due to the economic downturn in the fourth quarter of 2008, it was determined the relocation of the corporate offices would not take place and the lease, which was originally set up to run through January 2012, was terminated on December 29, 2008 with an effective termination date of January 2010. A portion of this leased space is currently occupied by our computer hardware and will continue to be occupied through December 2009.
 
Employees
 
As of December 31, 2008, we (through our Operating Partnership) employed approximately 780 full-time employees. Approximately 270 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
 
We may not be able to obtain funding or obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.
 
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile, which has caused a substantial deterioration in the credit and capital markets. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk, have made, and will likely continue to make, it difficult to obtain funding for our capital needs.


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Beginning in the second half of 2008, 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. In particular, as a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to borrowers’ current debt and reduced and, in some cases, ceased to provide funding to borrowers.
 
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. Moreover, 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 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 bank credit facility could be impaired.
 
We operate in a capital-intensive industry and rely on our bank credit facility to finance a significant portion of our capital expenditures. Our ability to borrow under our bank credit facility may be impaired because of the recent downturn in the financial markets, including issues surrounding the solvency of many institutional lenders and recent failures of several banks.
 
Specifically, we may be unable to obtain adequate funding under our bank credit facility because:
 
  •  one or more of our lenders may be unable or otherwise fail to meet its funding obligations;
 
  •  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
 
  •  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.
 
On February 27, 2009, we entered into an amendment to our bank credit facility, revising certain financial and other restrictive covenants under this facility through its maturity date. See Item 1, “Business—Amendments to Credit Documents.” There can be no assurance that we will be able to comply with any newly-negotiated covenants in the future or that we will be able to obtain waivers or amendments of these covenants in the event of future noncompliance. If we are not in compliance with these covenants, and if we are unable to secure necessary waivers or other amendments from the counterparties, we will not have access to our bank credit facility, which could significantly affect our ability to meet our expenses and operate our business. Further, such noncompliance could cause a default under the bank credit facility, which could result in acceleration of our outstanding debt.
 
If we are unable to access funds under our bank credit facility, we will need to meet our capital requirements, including some of our short-term capital requirements, using other sources. Due to current economic conditions, 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 bank 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. Furthermore, if the current pressures on credit continue or worsen, we may not be able to refinance our then-outstanding debt or replace our then-outstanding letters of credit when due, which could have a material adverse effect on our business.
 
We will not be able to pay cash distributions until our financial condition improves.
 
Our bank credit facility and senior secured note agreement contain covenants which limit our ability to make distributions to unitholders so long as we do not meet certain financial ratios and tests. Under the amended bank


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credit facility and senior secured note agreement, we may not make quarterly distributions to our unitholders unless the PIK notes have been repaid and the leverage ratio, as defined in the agreements, is less than 4.25 to 1.00. If the leverage ratio is between 4.00 to 1.00 and 4.25 to 1.00, we may make the minimum quarterly distribution of up to $0.25 per unit if the PIK notes have been repaid. If the leverage ratio is less than 4.00 to 1.00, we may make quarterly distributions to unitholders from available cash as provided by our partnership agreement if the PIK notes have been repaid. The PIK notes are due six months after the earlier of the refinancing or maturity of our bank credit facility. In order to repay the PIK notes prior to their scheduled maturity, we will need to amend or refinance our bank credit facility. Based on the amended provisions in our amended bank credit facility and senior secured note agreement, our current anticipated cash flows for 2009 and current economic conditions, we do not currently expect to be able to pay distributions to our unitholders in 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results. Even if we do not pay a distribution to unitholders, our unitholders may be liable for taxes on their share of our taxable income. See “— Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.”
 
In addition, even if our credit documents do not prohibit us from making distributions, we still may not have sufficient available cash each quarter to pay distributions to unitholders. Under the terms of our partnership agreement, we must pay our general partner’s fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the amount of natural gas transported in our gathering and transmission pipelines;
 
  •  the level of our processing and treating operations;
 
  •  the fees we charge and the margins we realize for our services;
 
  •  the price of natural gas;
 
  •  the relationship between natural gas and NGL prices;
 
  •  our level of operating costs; and
 
  •  restrictions on distributions contained in our bank credit facility.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
  •  the level of capital expenditures we make;
 
  •  the cost of acquisitions, if any;
 
  •  our debt service requirements;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to make working capital borrowings under our bank credit facility to pay distributions;
 
  •  prevailing economic conditions; and
 
  •  the amount of cash reserves established by our general partner in its sole discretion for the proper conduct of our business.
 
Because of these factors, even if our credit documents do not prohibit us from making distributions, we still may not be able, or may not have sufficient available cash to pay distributions to unitholders each quarter. Furthermore, you should also be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.


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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. 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 percent of liquids (POL) contracts that are directly impacted by the market price of NGLs. We also realize processing gross margins under fractionation 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, fee revenue under a POL agreement is directly impacted by NGL prices, and the decline of these prices in 2008 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 and the cost of fuel to extract during processing. During the last half of 2008, 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. The significant decline in crude oil prices and a related decline in NGL prices during the last half of 2008 had a significant negative impact on our margins, and may negatively impact our gross margin further if such declines continue.
 
In the past, the prices of natural gas and NGLs have been extremely volatile and we expect this volatility to continue. For example, in 2007, the NYMEX settlement price for natural gas for the prompt month contract ranged from a high of $7.59 per MMBtu to a low of $5.43 per MMBtu. In 2008, the same index ranged from $6.46 per MMBtu to $13.10 per MMBtu. A composite of the OPIS Mt. Belvieu monthly average liquids price based upon our average liquids composition in 2007 ranged from a high of approximately $1.58 per gallon to a low of approximately $0.92 per gallon. In 2008, the same composite ranged from approximately $2.01 per gallon to approximately $0.56 per gallon.
 
We may not be successful in balancing our purchases and sales. 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.
 
The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions and other factors, including:
 
  •  the impact of weather on the demand for oil and natural gas;
 
  •  the level of domestic oil and natural gas production;
 
  •  the level of domestic industrial and manufacturing activity;
 
  •  the availability of imported oil, natural gas and NGLs;
 
  •  international demand for oil and NGLs;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the availability of local, intrastate and interstate transportation systems;
 
  •  the availability of downstream NGL fractionation facilities;


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  •  the availability and marketing of competitive fuels;
 
  •  the impact of energy conservation efforts; and
 
  •  the extent of governmental regulation and taxation.
 
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 Disclosures about Market Risk.”
 
Due to our lack of asset diversification, adverse developments in our gathering, transmission, treating, processing and producer services businesses would materially impact our financial condition.
 
We rely exclusively on the revenues generated from our gathering, transmission, treating, 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 may 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. 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. 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 could result in lower volumes being transported on our pipeline and gathering systems and processing through our processing plants. We have seen a decline in drilling activity by gas producers in our areas of operation during the fourth quarter of 2008. In addition, industry drilling rig count surveys published in early 2009 show substantial declines in rigs in operation as compared to 2008. Several of our customers, including one of our largest customers in the Barnett Shale, have recently announced drilling plans for 2009 that are substantially below their drilling levels during 2008. A significant reduction in 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.


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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 bank 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. We have hedged only portions of our variable-rate debt and expected natural gas supply, NGL production and natural gas requirements. We continue to have 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.
 
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:
 
  •  hedging can be expensive, particularly during periods of volatile prices;
 
  •  our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and
 
  •  available hedges may not correspond directly with the risks against which we seek protection. For example:
 
  •  the duration of a hedge may not match the duration of the risk against which we seek protection;
 
  •  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
 
  •  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 economically 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 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 treating and processing plants, 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


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gas reserves. For example, as oil and natural gas prices have recently decreased, there has been a corresponding decrease in drilling activity. Tax policy changes 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 associated with our assets including, with respect to south Louisiana and the Gulf of Mexico assets, 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 the third and fourth quarters of 2008, our business was negatively impacted by hurricanes Gustav and Ike, which came ashore in the Gulf Coast in September. Although the majority of our assets in Texas and Louisiana sustained minimal physical damage from these hurricanes and promptly resumed operations, 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 we do not anticipate that gas production to our south Louisiana plants will recover to pre-hurricane levels until mid-2009, when all repairs are expected to be complete. Additionally, one of our south Louisiana processing plants, the Sabine Pass processing plant, which is located on the shoreline of the Louisiana Gulf Coast, sustained some physical damage. The Sabine Pass processing plant was repaired during the fourth quarter of 2008 and the plant was returned to service in early January 2009. Our operations in north Texas were also impacted by these hurricanes because operations at Mt. Belvieu, Texas, a central distribution point for NGL sales where several fractionators are located which fractionate NGLs from the entire United States, were interrupted as a result of these storms. These storms resulted in an adverse impact to our gross margin of approximately $22.9 million in the last half of 2008.
 
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:
 
  •  adverse weather conditions, including hurricanes and tropical storms;
 
  •  delays or decreases in production, the availability of equipment, facilities or services; and
 
  •  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.
 
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 and our treating plants, 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.


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Growing our business by constructing new pipelines and processing and treating 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 local ordinances.
 
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, processing and treating facilities. The construction of pipelines and gathering, processing and treating 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 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:
 
  •  the inability to integrate the operations of recently acquired businesses or assets;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  the loss of customers or key employees from the acquired businesses;
 
  •  a significant increase in our indebtedness; and
 
  •  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 will be limited due to our lack of access to capital markets and due to restrictions under our borrowing agreements.
 
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.


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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.
 
For the year ended December 31, 2008, approximately 46.0% of our sales of gas which were 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. 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.
 
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 under existing contracts, we would be adversely affected unless we were able to make comparably profitable arrangements with other customers. Several of our customers, including one of our largest customers in the Barnett Shale, have recently announced drilling plans for 2009 that are substantially below their drilling levels during 2008. Agreements with key customers provide for minimum volumes of natural gas that each customer must purchase until the expiration of the term of the applicable agreement, subject to certain force majeure provisions. Customers may default on their obligations to purchase the minimum volumes 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, treating and processing of natural gas and storage of residue gas, including:
 
  •  damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism;
 
  •  inadvertent damage from construction and farm equipment;
 
  •  leaks of natural gas, NGLs and other hydrocarbons; and
 
  •  fires and explosions.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our operations are concentrated in Texas, Louisiana and the Mississippi Gulf Coast, and a natural disaster or other hazard affecting this region could have a material adverse effect on our 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. Our business interruption insurance covers only our Gregory processing plant. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.


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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. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, and the possibility that infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. Instability in the financial markets as a result of terrorism, the war in Iraq or future developments could also affect our ability to raise capital.
 
Changes in the insurance markets attributable to the threat of terrorist attacks have made certain types of insurance more difficult for us to obtain. Our insurance policies now generally exclude acts of terrorism. Such insurance is not available at what we believe to be acceptable pricing levels. A lower level of economic activity could also result in a decline in energy consumption, which could adversely affect our revenues or restrict our future growth.
 
Federal, state or local regulatory measures could adversely affect our business.
 
While the FERC generally does not regulate our operations, it influences certain aspects of our business and the market for our products. 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 NGPA. Not only are our intrastate natural gas pipeline operations subject to limited rate regulation by FERC, but they are also 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.
 
Our natural gas gathering activities generally are exempt from FERC regulation under the NGA. 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.
 
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 Oklahoma and 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


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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 of 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 were approximately at $3.2 million, $1.2 million, and $1.1 million for the years ended December 31, 2008, 2007, and 2006, respectively. We expect the costs for compliance with TRRC and DOT regulations to be approximately $3.6 million during 2009. 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 the Partnership’s operations continue to expand into and around urban, or more populated areas, such as the Barnett Shale, it may incur additional expenses to mitigate noise, odor and light that may be emitted in our operations, and expenses related to the appearance of its facilities. Municipal and other local or state regulations are imposing various obligations, including, among other things, regulating the location of the Partnership’s facilities, imposing limitations on the noise levels of its facilities and requiring certain other improvements that increase the cost of its facilities. The Partnership is also subject to claims by neighboring landowners for nuisance related to the construction and operation of its facilities, which could subject it to damages for declines in neighboring property values due to its construction and operation of facilities.
 
Our business involves hazardous substances and may be adversely affected by environmental regulation.
 
Many of the operations and activities of our gathering systems, plants and other facilities, including our south Louisiana processing assets, 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 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 through which our gathering systems pass, 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 or 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 products, 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 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.


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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. controls our general partner and owned a 34% limited partner interest in us as of December 31, 2008. Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests.
 
As of December 31, 2008, Crosstex Energy, Inc. indirectly owned an aggregate limited partner interest of approximately 34% 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
 
  •  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;
 
  •  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;
 
  •  our general partner’s affiliates may engage in limited competition with us;
 
  •  our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;
 
  •  our general partner decides whether to retain separate counsel, accountants or others to perform services for us;
 
  •  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 a distribution on our subordinated units or to make incentive distributions or hasten the expiration of the subordination period; and
 
  •  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:
 
  •  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;
 
  •  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 662/3% of the outstanding units voting together as a single class. Because affiliates of the general partner controlled approximately 34% of all the units as of December 31, 2008, the general partner could not be removed without the consent of the general partner and its affiliates.
 
Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include, in most cases, charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
 
In addition, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% 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.


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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 common 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. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
 
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  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% 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


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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 tax on our income at corporate rates of up to 35% (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.
 
A change in current law or a change in our business could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, 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. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. 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.
 
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the costs of any contest will be borne by us and, therefore, indirectly by our unitholders and our general partner.
 
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 prospectus 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 income from us 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,


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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 in the near future. See “— Restrictions in our bank credit facility may prevent us from paying distributions to our unitholders.”
 
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, will likely be ordinary income to the unitholder. Should the IRS successfully contest some positions we take, unitholders could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. In addition, 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) 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 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 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 and could result in a deferral of depreciation deductions allowable in computing our taxable income.
 
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. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or


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may not be applied retroactively. Specifically, federal income tax legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. Although the currently proposed legislation would not appear to affect our tax 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, Oklahoma, Louisiana, New Mexico, Arkansas, Mississippi and Alabama. Oklahoma, Louisiana, New Mexico, Arkansas, Mississippi and Alabama impose an income tax, generally. Texas does not impose a state income tax on individuals, but does impose a franchise tax (to which we will be subject) on certain partnerships and other entities. 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.
 
Item 1B.   Unresolved Staff Comments
 
We do not have any unresolved staff comments.


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Item 2.   Properties
 
A description of our properties is contained in “Item 1. Business.”
 
Title to Properties
 
Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee. Our processing plants are located on land that we lease or own in fee. Our treating facilities are generally located on sites provided by producers or other parties.
 
We believe that we have satisfactory title to all of our rights-of-way and land assets. Title to these assets may be subject to encumbrances or defects. We believe that none of such encumbrances or defects should materially detract from the value of our assets or from our interest in these assets or should materially interfere with their use in the operation of our business.
 
Item 3.   Legal Proceedings
 
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, at any given time we may be a defendant in various legal proceedings and litigation arising in the ordinary course of business, including litigation on disputes related to contracts, use or damage and personal injury. Additionally, as we continue to expand our operations into more urban, populated areas, such as the Barnett Shale, we may see an increase in claims brought by area landowners, such as nuisance claims and other claims based on property rights. Except as otherwise set forth herein, we do not believe that any pending or threatened claim or dispute is material to our financial results or our operations. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
 
On November 15, 2007, Crosstex CCNG Processing Ltd. (“Crosstex Processing”), our wholly-owned subsidiary, received a demand letter from Denbury Onshore, LLC (“Denbury”), asserting a claim for breach of contract and seeking payment of approximately $11.4 million in damages. The claim arises from a contract under which Crosstex Processing processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex Processing breached the processing contract (the “Processing Contract”) by failing to build a processing plant of a certain size and design, resulting in Crosstex Processing’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex Processing failed to provide specific notices required under the Processing Contract. On December 4, 2007 and again on February 14, 2008, Denbury sent Crosstex Processing letters demanding that its claim be arbitrated pursuant to an arbitration provision in the Processing Contract. Denbury subsequently requested that the parties attempt to mediate the matter before any arbitration proceeding is initiated. On April 15, 2008, the parties mediated the matter unsuccessfully. On December 4, 2008, Denbury initiated formal arbitration proceedings in Dallas, Texas against Crosstex Processing, Crosstex Energy Services, L.P., Crosstex North Texas Gathering, L.P., and Crosstex Gulf Coast Marketing, Ltd., seeking $11.4 million and additional unspecified damages. On December 23, 2008, Crosstex Processing filed an answer denying Denbury’s allegations and a counterclaim seeking a declaratory judgment that its processing plant is uneconomic pursuant to the terms of the Processing Contract, allowing cancellation of the contract. Crosstex Energy, Crosstex Marketing, and Crosstex Gathering also filed an answer denying Denbury’s allegations and asserting that they are improper parties as Denbury’s claim is for breach of the Processing Contract and none of these entities is a party to that agreement. Crosstex Gathering also filed a counterclaim seeking approximately $40.0 million in damages for the value of the NGLs it is entitled to under its Gas Gathering Agreement with Denbury. Once the three-person arbitration panel has been named and cleared conflicts, the arbitration panel will hold a preliminary conference with the parties to set a date for the final hearing and other case deadlines and to establish discovery limits. Although it is


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not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse effect on our consolidated results of operations or financial position.
 
During 2007 and 2008 eleven lawsuits were filed against the Partnership and its subsidiaries by owners of property located near processing facilities or compression facilities constructed by us as part of our systems in north Texas. The actions are pending in state court in Parker County and Denton County, Texas. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. The property owners are seeking compensatory and punitive damages, attorney’s fees, inverse condemnation and injunctive relief. At this time, five cases are set for trial during 2009, three of which have pending settlements, and one new case has been filed in February 2009. The remaining cases have not yet been set for trial. Discovery is underway. Although it is not possible to predict the ultimate outcomes of these matters, we do not believe that these claims will have a material adverse impact on our consolidated results of operations or financial condition.
 
On July 22, 2008, SemStream, L.P. and certain of its subsidiaries filed voluntary petitions in the U.S. Bankruptcy Court for the District of Delaware 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 $2.2 million for July 2008 sales. We believe the July sales of $2.2 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 approximately $2.2 million but the allowance of the administrative claim status is still subject to approval of the bankruptcy court in accordance with the administrative claim allowance procedures order in the case. We evaluated these receivables for collectability and provided a valuation allowance of $3.1 million during 2008.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
No matters were submitted to security holders during the fourth quarter of the year ended December 31, 2008.
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
 
Our common units are listed on the NASDAQ Global Select Market under the symbol “XTEX”. On February 17, 2009, the closing market price for the common units was $4.05 per unit and there were approximately 11,000 record holders and beneficial owners (held in street name) of our common units and nine record holders of our 3,875,340 senior subordinated series D units. There is no established public trading market for our senior subordinated series D units.


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The following table shows the high and low closing sales prices per common unit, as reported by the NASDAQ Global Select Market, for the periods indicated.
 
                         
    Common Unit Price
       
    Range(a)     Cash Distribution
 
    High     Low     Paid Per Unit(a)  
 
2008:
                       
Quarter Ended December 31
  $ 17.41     $ 3.50     $ 0.25  
Quarter Ended September 30
    28.33       18.16       0.50  
Quarter Ended June 30
    34.10       28.40       0.63  
Quarter Ended March 31
    32.67       30.03       0.62  
2007:
                       
Quarter Ended December 31
  $ 34.91     $ 31.02     $ 0.61  
Quarter Ended September 30
    38.27       32.78       0.59  
Quarter Ended June 30
    36.45       33.56       0.57  
Quarter Ended March 31
    39.56       33.49       0.56  
 
 
(a) For each quarter, an identical cash distribution was paid on all outstanding subordinated units (excluding senior subordinated units).
 
Unless restricted by the terms of our credit facility, within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our general partner determines are necessary to:
 
  •  provide for the proper conduct of our business;
 
  •  comply with applicable law, any of our debt instruments, or other agreements; or
 
  •  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
 
  •  plus all cash on hand for the quarter resulting from working capital borrowings made after the end of the quarter on the date of determination of available cash.
 
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 distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. If our leverage ratio, as defined in the credit facility, falls below a certain level we will be prohibited from making distributions or from making more than the minimum quarterly distributions. Based on our forecasted leverage ratios for 2009, we do not anticipate making quarterly distributions during 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results. See Item 1, “Business — Amendments to Credit Documents.” Additionally, we are prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default is existing, under our credit facility. Please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Description of Indebtedness.”


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Conversion of Senior Subordinated Series D Units
 
The 3,875,340 senior subordinated series D units are scheduled to convert into common units on March 23, 2009. Since the distribution for the quarter ended December 31, 2008 was less than $0.62 per unit, the senior subordinated units will convert into common units at a ratio of 1.05 common units for each senior subordinated series D unit.
 
Equity Compensation Plan Information
 
                         
            Number of Securities
            Remaining Available for
    Number of Securities to
      Future Issuance Under
    be Issued Upon Exercise
  Weighted-Average Price
  Equity Compensation Plan
    of Outstanding Options,
  of Outstanding Options,
  (Excluding Securities
Plan Category
  Warrants, and Rights   Warrants and Rights   Reflected in Column(a))
    (a)   (b)   (c)
 
Equity Compensation Plans Approved By Security Holders
    N/A       N/A       N/A  
Equity Compensation Plans Not Approved By Security Holders
    2,002,760 (1)(2)   $ 30.64 (3)     1,915,696  
 
 
(1) Our general partner has adopted and maintains a long term incentive plan for our officers, employees and directors. See Item 11, “Executive Compensation — Compensation Discussion and Analysis.” The plan, as amended, provides for issuance of a total of 4,800,000 common unit options and restricted units.
 
(2) The number of securities includes (i) 477,858 restricted units that have been granted under our long-term incentive plan that have not vested, and (ii) 220,708 performance units which could result in grants of restricted units in the future.
 
(3) The exercise prices for outstanding options under the plan as of December 31, 2008 range from $10.00 to $37.31 per unit.
 
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 selected historical financial data are derived from the audited financial statements of Crosstex Energy, L.P. In addition, our summary historical financial and operating data include the results of operations of the LIG assets beginning in April 2004, the Graco assets beginning January 2005, the Cardinal assets beginning May 2005, the south Louisiana processing assets beginning November 2005, the Hanover assets beginning January 2006, 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
                                         
    Crosstex Energy, L.P.  
    Years Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per unit data)  
 
Statement of Operations Data:
                                       
Revenues:
                                       
Midstream
  $ 4,838,747     $ 3,791,316     $ 3,075,481     $ 2,982,874     $ 1,948,021  
Treating
    64,953       53,682       52,095       38,838       24,871  
Profit on energy trading activities
    3,349       4,090       2,510       1,568       2,228  
                                         
Total revenues
    4,907,049       3,849,088       3,130,086       3,023,280       1,975,120  
                                         
Operating costs and expenses:
                                       
Midstream purchased gas
    4,471,308       3,468,924       2,859,815       2,860,823       1,861,204  
Treating purchased gas
    14,579       7,892       9,463       9,706       5,274  


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    Crosstex Energy, L.P.  
    Years Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per unit data)  
 
Operating expenses
    169,048       125,149       98,794       54,658       38,340  
General and administrative
    71,005       61,528       45,694       32,697       20,866  
(Gain) loss on derivatives
    (12,203 )     (6,628 )     (1,591 )     9,966       (414 )
Gain on sale of property
    (1,519 )     (1,667 )     (2,108 )     (8,138 )     (12 )
Impairments
    30,436                          
Depreciation and amortization
    131,187       106,639       80,518       33,841       20,855  
                                         
Total operating costs and expenses
    4,873,841       3,761,837       3,090,585       2,993,553       1, 946,113  
                                         
Operating income
    33,208       87,251       39,501       29,727       29,007  
                                         
Other income (expense):
                                       
Interest expense, net
    (102,675 )     (79,403 )     (51,427 )     (15,767 )     (9,220 )
Other income
    27,757       683       183       392       798  
                                         
Total other income (expense)
    (74,918 )     (78,720 )     (51,244 )     (15,375 )     (8,422 )
                                         
Income (loss) from continuing operations before minority interest, income taxes and cumulative effect change in accounting principle
    (41,710 )     8,531       (11,743 )     14,352       20,585  
Minority interest subsidiary
    (311 )     (160 )     (231 )     (441 )     (289 )
Income tax provision
    (2,765 )     (964 )     (222 )     (216 )     (162 )
                                         
Income (loss) from continuing operations before discontinued operations and cumulative effect of change in accounting principle
    (44,786 )     7,407       (12,196 )     13,695       20,134  
Discontinued Operations:
                                       
Income from discontinued operations
    5,752       6,482       7,316       5,505       3,570  
Gain on sale of discontinued operations
    49,805                          
                                         
Discontinued operations
    55,557       6,482       7,316       5,505       3,570  
                                         
Net income (loss) before cumulative effect of change in accounting principle
    10,771       13,889       (4,880 )     19,200       23,704  
Cumulative effect of change in accounting principle
                689              
                                         
Net income (loss)
  $ 10,771     $ 13,889     $ (4,191 )   $ 19,200     $ 23,704  
                                         
Net income (loss) per limited partner unit — basic
  $ (3.23 )   $ (0.20 )   $ (1.09 )   $ 0.56     $ 0.98  
Net income (loss) per limited partner unit — diluted
  $ (3.23 )   $ (0.20 )   $ (1.09 )   $ 0.51     $ 0.95  
Net income (loss) per limited partner senior subordinated unit A— basic and diluted
              $ 5.31              
Net income per limited partner senior subordinated unit series C — basic and diluted
  $ 9.44                          
Distributions per limited partner unit(1)
  $ 2.00     $ 2.33     $ 2.18     $ 1.93     $ 1.70  
Balance Sheet Data (end of period):
                                       
Working capital deficit
  $ (32,910 )   $ (46,888 )   $ (79,936 )   $ (11,681 )   $ (34,724 )
Property and equipment, net
    1,527,280       1,425,162       1, 105,813       667,142       324,730  
Total assets
    2,533,266       2,592,874       2,194,474       1,425,158       586,771  
Long-term debt
    1,263,706       1,223,118       987,130       522,650       148,700  
Partners’ equity
    794,421       784,826       711,877       401,285       144,050  
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
Operating activities
  $ 173,750     $ 114,818     $ 113,010     $ 14,010     $ 48,103  
Investing activities
    (186,810 )     (411,382 )     (885,825 )     (615,017 )     (124,371 )
Financing activities
    14,554       295,882       772,234       596,615       81,899  
Other Financial Data:
                                       
Midstream gross margin
  $ 370,788     $ 326,482     $ 218,176     $ 123,619     $ 89,045  
Treating gross margin
    50,374       45,790       42,632       29,132       19,597  
                                         
Total gross margin(2)
  $ 421,162     $ 372,272     $ 260,808     $ 152,751     $ 108,642  
                                         

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    Crosstex Energy, L.P.  
    Years Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per unit data)  
 
Operating Data:
                                       
Pipeline throughput (MMBtu/d)
    2,608,000       2,114,000       1,356,000       1,126,000       1,289,000  
Natural gas processed (MMBtu/d)(3)
    1,812,000       2,057,000       2,032,000       1,921,000       425,000  
Producer Services (MMBtu/d)
    85,000       94,000       138,000       175,000       210,000  
 
 
(1) Distributions include fourth quarter 2008 distributions of $0.25 per unit paid in February 2009; fourth quarter 2007 distributions of $0.61 per unit paid in February 2008; fourth quarter 2006 distributions of $0.56 per unit paid in February 2007; fourth quarter 2005 distributions of $0.51 per unit paid in February 2006; fourth quarter 2004 distributions of $0.45 per unit paid in February 2005; and fourth quarter 2003 distributions of $0.375 per unit paid in February 2004.
 
(2) Gross margin is defined as revenue, including treating fee revenues and profit on energy trading activities, less related cost of purchased gas.
 
(3) For the year ended 2005, processed volumes include a daily average for the south Louisiana processing plants for November 2005 and December 2005, the two-month period these assets were operated by us.
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the financial statements included in this report.
 
Overview
 
We are a Delaware limited partnership formed on July 12, 2002 to indirectly acquire substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the north Texas Barnett Shale area, and in Louisiana and Mississippi. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and NGLs, as well as providing certain producer services, while our Treating division focuses on the removal of contaminants from natural gas and NGLs to meet pipeline quality specifications. For the year ended December 31, 2008, approximately 88.0% of our gross margin was generated in the Midstream division with the balance in the Treating division. We manage our operations by focusing on gross margin because our business is generally to purchase and resell natural gas for a margin, or to gather, process, transport, market or treat natural gas or NGLs for a fee. We buy and sell most of our natural gas at a fixed relationship to the relevant index price. In addition, we receive certain fees for processing based on a percentage of the liquids produced and enters into hedge contracts for our expected share of the liquids produced to protect our margins from changes in liquids prices.
 
During the past five years we have grown significantly as a result of our construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2004 through December 31, 2008, we have invested over $2.3 billion to develop or acquire new assets. The purchased assets were acquired from numerous sellers at different periods and were accounted for under the purchase method of accounting. Accordingly, the results of operations for such acquisitions are included in our financial statements only from the applicable date of the acquisition. As a consequence, the historical results of operations for the periods presented may not be comparable.
 
Our Midstream segment margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, and the volumes of NGLs

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handled at our fractionation facilities. Our Treating segment margins are largely a function of the number and size of treating plants in operation. We generate Midstream revenues from six primary sources:
 
  •  purchasing and reselling or transporting natural gas on the pipeline systems we own;
 
  •  processing natural gas at our processing plants and fractionating and marketing the recovered NGLs;
 
  •  treating natural gas at our treating plants;
 
  •  providing compression services; and
 
  •  providing off-system marketing services for producers.
 
With respect to our Midstream services, we generally gather or transport gas owned by others through our facilities for a fee, or we buy natural gas from a producer, plant or shipper at either a fixed discount to a market index or a percentage of the market index, then transport and resell the natural gas. In our purchase/sale transactions, the resale price is generally based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas.
 
We also realize margins in our Midstream segment from our processing services primarily through three different contract arrangements: processing margins (margin), percentage of liquids (POL) or fee based. Under the margin and POL contract arrangements our margins are higher during periods of high liquid prices relative to natural gas prices. Under fee based contracts our margins are driven by throughput volume. See “—Commodity Price Risk.”
 
We generate Treating revenues under three types of arrangements:
 
  •  a volumetric fee based on the amount of gas treated, which accounted for approximately 11.0% of operating income in our Treating division for the years ended December 31, 2008 and 2007;
 
  •  a fixed fee for operating a plant for a certain period, which accounted for approximately 62.0% and 59.0% of operating income in our Treating division for the years ended December 31, 2008 and 2007, respectively; and
 
  •  a fee arrangement in which the producer operates the plant, which accounted for approximately 27.0% and 30.0% of operating income in our Treating division for the years ended December 31, 2008 and 2007, respectively.
 
Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.
 
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
 
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Numerous events during 2008 have severely restricted current liquidity in the capital markets throughout the United States and around the world. The ability to raise money in the debt and equity markets has diminished significantly and, if available, the cost of funds has increased substantially. One of the features driving investments


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in MLPs , including the Partnership, over the past few years has been the distribution growth offered by MLPs due to liquidity in the financial markets for capital investments to grow distributable cash flow through development projects and acquisitions. Future growth opportunities have been and are expected to continue to be constrained by the lack of liquidity in the financial markets.
 
In addition, our business has been significantly impacted by the substantial decline in crude oil prices during the last half of 2008 from a high of approximately $145 per Bbl in July 2008 to a low of approximately $34 per Bbl in December 2008 (based on NYMEX futures daily close prices for the prompt month), a 76.7% decline, and the related 78.2% decline in NGL prices from a high of $2.19 per gallon in July 2008 to a low of $0.48 per gallon in December 2008 (based on the OPIS Mt. Belvieu daily average spot liquids prices). Crude oil prices reflected on NYMEX during January and February 2009 have fluctuated, to a lesser extent, between $49 per Bbl and $35 per Bbl while the OPIS Mt. Belvieu NGL prices have improved slightly ranging from $0.81 per gallon and $0.62 per gallon. The declines in NGL prices have negatively impacted our gross margin for the fourth quarter of 2008 and could continue to negatively impact our gross margin (revenue less cost of gas purchases) in 2009. A significant percentage of inlet gas at our processing plants is settled under percent of liquids (POL) agreements or fractionation margin (margin) contracts. Over the past two years the inlet processing volumes associated with POL and margin contracts were approximately 70%, on a combined basis, of the total volume of gas processed. The POL fees are denominated in the form of a share of the liquids extracted. Therefore, fee revenue under a POL agreement is directly impacted by NGL prices and the decline of these prices in 2008 contributed to a significant decline in gross margin from processing. Under the POL settlement terms, we are not responsible for the fuel or shrink associated with processing. Under margin contracts we realize a gross margin from processing based upon the difference in the value of NGLs extracted from the gas less the value of the product in its gaseous state and the cost of fuel to extract. This is often referred to as the fractionation spread. During the last half of 2008 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 also negatively impacted due to the commodity price environment. If the current weakness in the economy continues for a prolonged period, it would likely further reduce demand for gas and for NGL products, such as ethane, a primary feedstock for the petrochemical and manufacturing industries, and result in continued lower natural gas and NGL prices. Although we have seen some improvement in NGL prices and the fractionation spread in the early months of 2009 over the levels experienced in December 2008, we believe that our processing margins in 2009 will be substantially lower than the processing margins realized in 2008 based on current market indicators. For the year ended December 31, 2008, approximately 38.7% of our gross margin was attributable to gas processing as compared to 46.1% of our gross margin for the year ended December 31, 2007. See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk” for a description of our contractual processing arrangements.
 
Natural gas prices have declined by approximately 61.0%, from a high of $13.58 per MMBtu in July 2008 to a low of $5.29 per MMBtu in December 2008 (based on NYMEX futures daily close prices for the prompt month). Natural gas prices have declined even further during January and February 2009 with prices ranging from $6.07 in early January to $4.01 in mid-February. Many of our customers finance their drilling activity with cash flow from operations, which have been negatively impacted by the declines in natural gas and crude oil prices, or through the incurrence of debt or issuance of equity, which markets have been adversely impacted by global financial market conditions. We believe that the adverse price changes coupled with the overall downturn in the economy and the constrained capital markets will put downward pressure on drilling budgets for gas producers which could result in lower volumes being transported on our pipeline and gathering systems and processing through our processing plants. We have seen a decline in drilling activity by gas producers in our areas of operations during the fourth quarter of 2008. In addition, industry drilling rig count surveys published in early 2009 show substantial declines in rigs in operation as compared to 2008. Several of our customers, including one of our largest customers in the Barnett Shale, have recently announced drilling plans for 2009 that are substantially below their drilling levels during 2008.
 
Our business was also negatively impacted by hurricanes Gustav and Ike, which came ashore in the Gulf Coast in September 2008. Although the majority of our assets in Texas and Louisiana sustained minimal physical damage from these hurricanes and promptly resumed operations, several offshore production platforms and pipelines that transport gas production to our Pelican, Eunice, Sabine Pass and Blue Water processing plants in south Louisiana


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were damaged by the storms. Some of the repairs to these offshore facilities were completed during the fourth quarter of 2008 but we do not anticipate that gas production to our south Louisiana plants will recover to pre-hurricane levels until mid-2009, when all repairs are expected to be complete. Additionally, one of our south Louisiana processing plants, the Sabine Pass processing plant, which is located on the shoreline of the Louisiana Gulf Coast, sustained some physical damage. The Sabine Pass processing plant was repaired during the fourth quarter of 2008 and the plant was returned to service in early January 2009. Our operations in north Texas were also impacted by these hurricanes because operations at the Mt. Belvieu, Texas, a central distribution point for NGL sales where several fractionators are located which fractionate NGLs from the entire United States, were interrupted as a result of these storms. These storms resulted in an adverse impact to our gross margin of approximately $22.9 million.
 
Two of our facilities, one in south Louisiana and one in north Texas, were also partially damaged by fires during 2008. Although substantially all of the property repairs were covered by insurance, our Sabine Pass processing plant in south Louisiana was out of service for approximately one month. The loss of operating income due to the fire at the Godley compressor station in north Texas was minimal because we were successful in rerouting the gas to our other facilities in the area until the damaged compressor was replaced. The estimated loss in gross margin as a result of these fires is $0.9 million.
 
Acquisitions and Expansion
 
We have grown significantly through asset purchases and construction and expansion projects in recent years. This growth creates many of the major differences when comparing operating results from one period to another. The most significant asset purchases since January 2006 were the acquisition of midstream assets from Chief Holdings, LLC, or Chief in June 2006, the Hanover Compression Company treating assets in February 2006 and the amine-treating business of Cardinal Gas Solutions L.P. in October 2006. In addition, internal expansion projects in north Texas and Louisiana have contributed to the increase in our business during 2006, 2007 and 2008.
 
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. The acquired systems included gathering pipeline, a 125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At the closing of that acquisition, 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 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 and 2008 and will continue to be a core area during 2009. Since the date of the acquisition through December 31, 2008, we connected 444 new wells to our gathering system and significantly increased the dedicated acreage owned by other producers. Our processing capacity in the Barnett Shale is 280 MMcf/d including the 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. In 2007 and 2008, we constructed a 29-mile expansion in north Johnson County to our north Texas gathering systems. The first phase of the expansion commenced operation in September 2007. The last two phases of the expansion commenced operation in May and July of 2008. The total gathering capacity of this 29-mile expansion is currently 235 MMcf/d and is expected to be increased to approximately 400 MMcf/d in April 2009 by the addition of compression. We have also installed two 40 gallon per minute and one 100 gallon per minute amine treating plants to provide carbon dioxide removal capability. As of December 2008, the capacity of our north Texas gathering system was approximately 1,100 MMcf/d and total throughput on our north Texas gathering systems, including the north Johnson County expansion, had increased from approximately 115,000 MMBtu/d at the time of the Chief acquisition to approximately 796,000 MMBtu/d.
 
In April 2008, we commenced construction of an $80.0 million natural gas processing facility called Bear Creek in Hood County near our existing North Texas Assets. The new plant will have a gas processing capacity of 200 MMcf/d. Due to the recent decline in commodity prices and the corresponding decline in drilling activity, we do not anticipate that the additional processing capacity provided by the Bear Creek plant will be needed until late 2010 or in 2011. Therefore, we have decided to put this construction project on hold until the demand for this processing capacity returns, at which time we will seek to obtain financing for this project. As of December 31, 2008, we have


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spent approximately $20.2 million on this project for the construction of a portion of the plant that will be utilized when the plant is completed in the future.
 
On February 1, 2006, we acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.7 million.
 
On October 3, 2006, we acquired the amine-treating business of Cardinal Gas Solutions L.P. for $6.3 million. The acquisition added 10 dew point control plants and 50% of seven amine-treating plants to our plant portfolio. On March 28, 2007, we acquired the remaining 50% interest in the amine-treating plants for approximately $1.5 million.
 
Our NTP, which commenced service in April 2006, consists of a 133-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 NGPL, Kinder Morgan, HPL, Atmos and other markets. As of December 2008, the total throughput on the NTP was approximately 300,000 MMBtu/d. The NTP also will interconnect with a new interstate gas pipeline under construction by Boardwalk Pipeline Partners, L.P. known as the Gulf Crossing Pipeline which is expected to be in service in March 2009. The Gulf Crossing Pipeline is expected to provide our customer’s access to premium midwest and east coast markets.
 
In April 2007, we completed construction and commenced operations on our north Louisiana expansion, which is an extension of our LIG system designed to increase take-away pipeline capacity to the producers developing natural gas in the fields south of Shreveport, Louisiana. The north Louisiana expansion consists of approximately 63 miles of 24” mainline with 9 miles of 16” gathering lateral pipeline and 10,000 horsepower of new compression referred to as our Red River lateral. Our Red River lateral bisects the developing Haynesville Shale gas play in north Louisiana. The Red River lateral was operating at near capacity during 2008 so we added 35 MMcf/d of capacity by adding compression during the third quarter of 2008 bringing the total capacity of the Red River lateral to approximately 275 MMcf/d. As of December 31, 2008, the Red River lateral was flowing at approximately 225,000 MMBtu/d. Interconnects on the north Louisiana expansion include connections with the interstate pipelines of ANR Pipeline, Columbia Gulf Transmission, Texas Gas Transmission and Trunkline Gas.
 
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, fee revenue under a POL agreement is directly impacted by NGL prices, and the decline of these prices in 2008 contributed to a significant decline in gross margin from processing. We have a number of fractionation 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 and the cost of fuel to extract during processing. During the last half of 2008 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. The significant decline in crude oil prices and a related decline in NGL prices during the last half of 2008 had a significant negative impact on our margins, and may negatively impact our gross margin further if such declines continue.
 
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 4.0% of the natural gas we market is purchased at a


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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 Midstream and Treating divisions for the periods indicated.
 
                         
    Years Ended December 31,  
    2008     2007     2006  
    (Dollars in millions)  
 
Midstream revenues
  $ 4,838.7     $ 3,791.3     $ 3,075.5  
Midstream purchased gas
    (4,471.3 )     (3,468.9 )     (2,859.8 )
Profits on energy trading activities
    3.4       4.1       2.5  
                         
Midstream gross margin
    370.8       326.5       218.2  
                         
Treating revenues
    65.0       53.7       52.1  
Treating purchased gas
    (14.6 )     (7.9 )     (9.5 )
                         
Treating gross margin
    50.4       45.8       42.6  
                         
Total gross margin
  $ 421.2     $ 372.3     $ 260.8  
                         
Midstream Volumes (MMBtu/d):
                       
Gathering and transportation
    2,608,000       2,114,000       1,356,000  
Processing
    1,812,000       2,057,000       2,032,000  
Producer services
    85,000       94,000       138,000  
Treating Plants in Operation at Year-end
    200       190       190  
 
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $370.8 million for the year ended December 31, 2008 compared to $326.5 million for the year ended December 31, 2007, an increase of $44.3 million, or 13.6%. 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 resulting from the impact of hurricanes in the last half of the year. Profit on energy trading 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. Our gathering systems in the region and NTP accounted for $41.3 million and $9.1 million of this increase, respectively. Our processing facilities in the region contributed an additional $8.5 million of gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $8.2 million during the year ended December 31, 2008 over the same period in 2007. Processing plants in Louisiana experienced a margin decline of $20.2 million for the comparative twelve-month period in 2008 due to a less favorable NGL processing environment in the last half of the year and business interruptions resulting from the impact of hurricanes along the Gulf Coast. These unfavorable processing conditions also contributed to margin declines in south Texas on the Vanderbilt system and Gregory Processing facility of $2.9 million and $1.8 million, respectively. A throughput decline on the Gregory Gathering system resulted in a gross margin decrease of $1.6 million. These declines were partially offset by a gross margin increase on the CCNG system of $1.9 million due to an increase in throughput. The Mississippi system had a margin


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increase of $1.2 million due to increased throughput, and an expansion of the east Texas system contributed to a margin increase of $0.9 million for the comparable periods.
 
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. We estimate that these storms resulted in an approximately $22.9 million gross margin decrease for the year. The lost margin was primarily experienced at gas processing facilities along the Gulf Coast. However, processing facilities further inland in Louisiana and north Texas were indirectly impacted due to disruption in the NGL markets. In addition, approximately $0.9 million in gross margin was lost at the Sabine Pass plant in August 2008 due to downtime from fire damage. The fire occurred during an attempt to bring the plant back online following tropical storm Edouard.
 
Treating gross margin was $50.4 million for the year ended December 31, 2008 compared to $45.8 million for the year ended December 31, 2007, an increase of $4.6 million, or 10.0%. We had approximately 200 and 190 treating plants, dew point control plants, and related equipment in service at December 31, 2008 and 2007, respectively. Gross margin growth for the period of $3.2 million is attributable primarily to the increase in the number of plants and an increase in throughput on the volume based plants. Field services provided to producers also contributed gross margin growth of $1.4 million for the comparable periods.
 
Operating Expenses.  Operating expenses were $169.0 million for the year ended December 31, 2008 compared to $125.1 million for the year ended December 31, 2007, an increase of $43.9 million, or 35.1%. The increase is primarily attributable to the following factors:
 
  •  $35.8 million increase in Midstream operating expenses resulting primarily from growth and expansion in the NTP, NTG, north Louisiana and east Texas areas. Contractor services and labor costs increased $14.1 million, chemicals and materials increased $7.8 million, equipment rental increased $7.4 million and ad valorem taxes increased $2.4 million;
 
  •  $7.3 million increase in Treating operating expenses, including $2.6 million for materials and supplies, contractor services costs of $2.8 million to support maintenance projects, labor costs of $1.4 million as a result of market adjustments for field service employees and additional headcount and auto-related expenses of $0.5 million; and
 
  •  $0.7 million increase in technical services operating expense.
 
General and Administrative Expenses.  General and administrative expenses were $71.0 million for the year ended December 31, 2008 compared to $61.5 million for the year ended December 31, 2007, an increase of $9.5 million, or 15.4%. The increase is primarily attributable to the following factors:
 
  •  $5.5 million increase in rental expense resulting primarily from additional office rent and including $3.4 million related to lease termination fees for the cancelled relocation of our corporate headquarters;
 
  •  $3.1 million increase in bad debt expense due to the SemStream, L.P. bankruptcy;
 
  •  $1.8 million increase in other expenses, including professional fees and services and labor and benefit expenses; and
 
  •  $0.9 million decrease in stock-based compensation expense resulting primarily from the reduction of estimated performance-based restricted units and restricted shares.


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Gain/Loss on Derivatives.  We had a gain on derivatives of $12.2 million for the year ended December 31, 2008 compared to a gain of $6.6 million for the year ended December 31, 2007. The derivative transaction types contributing to the net gain are as follows (in millions):
 
                                 
    Years Ended December 31,  
    2008     2007  
(Gain)/Loss on Derivatives:
  Total     Realized     Total     Realized  
 
Basis swaps
  $ (7.2 )   $ (7.3 )   $ (8.1 )   $ (7.0 )
Processing margin hedges
    (3.6 )     (3.6 )     1.3       1.3  
Storage
    (0.7 )     (0.1 )     (0.5 )     (1.6 )
Third-party on-system swaps
    (0.6 )     (0.8 )     (0.2 )     (0.6 )
Puts
                0.8        
Other
    (0.1 )           0.1        
                                 
    $ (12.2 )   $ (11.8 )   $ (6.6 )   $ (7.9 )
                                 
 
Gain/Loss on Sale of Property.  Assets sold during the year ended December 31, 2008 generated a net gain of $1.5 million as compared to a gain of $1.7 million during the year ended December 31, 2007. The 2008 gain was primarily generated from the disposition of various small Treating and Midstream assets. The 2007 gain was primarily generated from the disposition of unused catalyst material and the disposition of a treating plant.
 
Impairments.  During the year ended December 31, 2008, we had an impairment expense of $30.4 million compared to no impairment expense for the year ended December 31, 2007. The impairment expense is comprised of:
 
  •  $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. At this time, we have not found an alternative source of new gas for the Blue Water plant so the plant ceased operation in January 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.
 
  •  $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.
 
  •  $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.
 
  •  $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 $11.0 million and the carrying amount of the plant exceeded the sale price by approximately $2.6 million.
 
  •  $1.0 million related to unused treating equipment — The impairment relates to older equipment in the Treating division that will not be used in our future operations.
 
Depreciation and Amortization.  Depreciation and amortization expenses were $131.2 million for the year ended December 31, 2008 compared to $106.6 million for the year ended December 31, 2007, an increase of $24.5 million, or 23.0%. Midstream depreciation and amortization increased $23.0 million due to the NTP, NTG


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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 $102.7 million for the year ended December 31, 2008 compared to $79.4 million for the year ended December 31, 2007, an increase of $23.3 million, or 29.3%. 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):
 
                 
    Years Ended December 31,  
    2008     2007  
 
Senior notes
  $ 33.1     $ 33.4  
Credit facility
    39.4       47.2  
Capitalized interest
    (2.7 )     (4.8 )
Mark to market interest rate swaps
    22.1       1.1  
Realized interest rate swaps
    4.6       (0.7 )
Interest income
    (0.3 )     (0.7 )
Other
    6.5       3.9  
                 
Total
  $ 102.7     $ 79.4  
                 
 
Income taxes.  Income tax expense was $2.8 million for the year ended December 31, 2008 compared to $1.0 million for the year ended December 31, 2007, an increase of $1.8 million. The increase relates primarily to the Texas margin tax.
 
Other Income.  Other income was $27.8 million for the year ended December 31, 2008 compared to $0.7 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. 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.
 
Discontinued Operations.  Discontinued operations were $55.6 million for the year ended December 31, 2008 compared to $6.5 million for the year ended December 31, 2007. In November 2008, we sold our undivided 12.4% interest in the Seminole gas processing plant to an unrelated third party and realized a gain on the sale of $49.8 million.
 
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
 
Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $326.5 million for the year ended December 31, 2007 compared to $218.2 million for the year ended December 31, 2006, an increase of $108.3 million, or 49.6%. This increase was primarily due to system expansions, increased system throughput and a favorable processing environment for natural gas and NGLs.
 
Crosstex acquired the NTG assets from Chief in June 2006. System expansion in the north Texas region and increased throughput on the NTP contributed $64.5 million of gross margin growth during the year ended December 31, 2007 over the same period in 2006. The NTG and NTP assets accounted for $34.1 million and $16.6 million of this increase, respectively. The processing facilities in the region contributed an additional $13.3 million of this gross margin increase. Operational improvements, system expansion and increased volume on the LIG system coupled with optimization and integration with the south Louisiana processing assets contributed margin growth of $22.6 million for 2007. Volume increases on the Mississippi system contributed gross margin growth of $5.7 million. The Plaquemine and Gibson plants contributed margin growth of $9.9 million due to a favorable gas processing environment. The favorable gas processing margin also led to a combined $5.3 million margin increase on the Vanderbilt and Gulf Coast systems.


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The favorable processing margins we realized during 2007 at several of our processing facilities may be higher than margins we currently are realizing or may realize in future periods due to the current economic environment and NGL prices. As discussed above under “— Commodity Price Risk”, we receive as a processing fee a percentage of the liquids recovered on a substantial portion of the gas processed through our plants. Also, during periods when processing margins are favorable due to liquids prices being high relative to natural gas prices, as existed during 2007, we have the ability to generate higher processing margins. We have the ability to bypass certain volumes when processing is uneconomical so we can avoid negative processing margins but our margins will be lower during these periods.
 
In addition, we have the ability to buy gas from and to sell gas to various gas markets through our pipeline systems. During 2007 we were able to benefit from price differentials between the various gas markets by selling gas into markets with more favorable pricing thereby improving our Midstream gross margin.
 
Treating gross margin was $45.8 million for the year ended December 31, 2007 compared to $42.6 million for the year ended December 31, 2006, an increase of $3.2 million, or 7.4%. There were approximately 190 treating and dew point control plants in service at December 31, 2007. Although the number of plants in service was unchanged from December 31, 2006, gross margin growth for 2007 is attributed to a higher average number of plants in service each month during 2007 compared to 2006.
 
Operating Expenses.  Operating expenses were $125.1 million for the year ended December 31, 2007 compared to $98.8 million for the year ended December 31, 2006, an increase of $26.4 million, or 26.7%. The increase in operating expenses primarily reflects costs associated with growth and expansion in the north Texas assets of $17.5 million, the south Texas assets of $1.8 million, LIG and the north Louisiana expansion of $3.7 million and Treating assets of $1.6 million. Operating expenses included $1.8 million of stock-based compensation expense in 2007 compared to $1.1 million of stock-based compensation expense in 2006.
 
General and Administrative Expenses.  General and administrative expenses were $61.5 million for the year ended December 31, 2007 compared to $45.7 million for the year ended December 31, 2006, an increase of $15.8 million, or 34.7%. Additions to headcount associated with the requirements of NTP and NTG assets and the expansion in north Louisiana accounted for $8.9 million of the increase. Consulting for system and process improvements resulted in $2.8 million of the increase. General and administrative expenses included stock-based compensation expense of $10.2 million and $7.4 million in 2007 and 2006, respectively.
 
Gain/Loss on Derivatives.  We had a gain on derivatives of $6.6 million for the year ended December 31, 2007 compared to a gain of $1.6 million for the year ended December 31, 2006. The derivative transaction types contributing to the net gain are as follows (in millions):
 
                                 
    Years Ended December 31,  
    2007     2006  
(Gain) Loss on Derivatives:
  Total     Realized     Total     Realized  
 
Basis swaps
  $ (8.1 )   $ (7.0 )   $ (0.7 )   $ (0.4 )
Processing margin hedges
    1.3       1.3              
Storage
    (0.5 )     (1.6 )     (2.9 )     (0.7 )
Third-party on-system swaps
    (0.2 )     (0.6 )     (1.5 )     (1.2 )
Puts
    0.8             3.6        
Other
    0.1             (0.1 )      
                                 
    $ (6.6 )   $ (7.9 )   $ (1.6 )   $ (2.3 )
                                 
 
Gain/Loss on Sale of Property.  Assets sold during the year ended December 31, 2007 generated a net gain of $1.7 million as compared to a gain of $2.1 million during the year ended December 31, 2006. The 2007 gain was primarily generated from the disposition of unused catalyst material and the disposition of a treating plant. The gain in 2006 primarily related to the sale of inactive gas processing facilities acquired as a part of the south Louisiana processing assets and as part of LIG acquisition.


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Depreciation and Amortization.  Depreciation and amortization expenses were $106.6 million for the year ended December 31, 2007 compared to $80.5 million for the year ended December 31, 2006, an increase of $26.1 million, or 32.4%. Midstream depreciation and amortization increased $25.8 million due to the NTP, NTG and north Louisiana expansion project assets.
 
Interest Expense.  Interest expense was $79.4 million for the year ended December 31, 2007 compared to $51.4 million for the year ended December 31, 2006, an increase of $28.0 million, or 54.4%. The increase relates primarily to an increase in debt outstanding as a result of acquisitions and other growth projects. Net interest expense consists of the following (in millions):
 
                 
    Years Ended December 31,  
    2007     2006  
 
Senior notes
  $ 33.4     $ 23.6  
Credit facility
    47.2       30.1  
Capitalized interest
    (4.8 )     (5.4 )
Mark to market interest rate swaps
    1.1       (0.1 )
Realized interest rate swaps
    (0.7 )      
Interest income
    (0.7 )     (1.1 )
Other
    3.9       4.3  
                 
Total
  $ 79.4     $ 51.4  
                 
 
Discontinued Operations.  Discontinued operations were $6.5 million for the year ended December 31, 2007 compared to $7.3 million for the year ended December 31, 2006. In November 2008, we sold our undivided 12.4% interest in the Seminole gas processing plant to an unrelated third party.
 
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 to two months 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


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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 the one to two months of 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 natural gas liquids. 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. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, 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 Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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:
 
  •  changes in general economic conditions in regions in which our markets are located;
 
  •  the availability and prices of natural gas supply;
 
  •  our ability to negotiate favorable sales agreements;
 
  •  the risks that natural gas exploration and production activities will not occur or be successful;
 
  •  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, transmission pipelines and natural gas treating plants. 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 Flows from Operating Activities.  Net cash provided by operating activities was $173.8 million, $114.8 million and $113.0 million for the years ended December 31, 2008, 2007 and 2006, respectively. Income before non-cash income and expenses and changes in working capital for 2008, 2007 and 2006 were as follows (in millions):
 
                         
    Years Ended December 31,
    2008   2007   2006
 
Income before non-cash income and expenses
  $ 160.9     $ 138.9     $ 88.3  
Changes in working capital
    12.9       (24.0 )     24.7  
 
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. The primary reason for the increased cash flow from income before non-cash income and expenses of $50.6 million from 2006 to 2007 was increased operating income from our expansion in north Texas during 2006 and 2007.
 
Cash Flows from Investing Activities.  Net cash used in investing activities was $186.8 million, $411.4 million and $885.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. Our primary investing activities for 2008, 2007 and 2006 were capital expenditures and acquisitions, net of accrued amounts, as follows (in millions):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Growth capital expenditures
  $ 257.3     $ 403.7     $ 308.8  
Acquisitions and asset purchases
                576.1  
Maintenance capital expenditures
    18.3       10.8       6.0  
                         
Total
  $ 275.6     $ 414.5     $ 890.9  
                         
 
Net cash invested in Midstream assets was $222.4 million for 2008, $385.8 million for 2007 and $746.7 million for 2006 (including $475.4 million related to the acquisition of assets from Chief). Net cash invested in Treating assets was $41.8 million for 2008, $23.5 million for 2007 and $86.8 million for 2006 (including $51.5 million related to the acquisition of Hanover assets). Net cash invested in other corporate assets was $11.4 million for 2008, $5.2 million for 2007 and $8.2 million for 2006.


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Cash flows from investing activities for the years ended December 31, 2008, 2007 and 2006 also include proceeds from property sales of $88.8 million, $3.1 million and $5.1 million, respectively. Sales in 2008 primarily relate to the sale of interest in the Seminole gas processing plant. The 2007 and 2006 sales primarily related to sales of inactive properties.
 
Cash Flows from Financing Activities.  Net cash provided by financing activities was $14.6 million, $295.9 million and $772.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. Our financing activities primarily relate to funding of capital expenditures and acquisitions. Our financings have primarily consisted of borrowings under our bank credit facility, borrowings under capital lease obligations, equity offerings and senior note issuances for 2008, 2007 and 2006 as follows (in millions):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Net borrowings under bank credit facility
  $ 50.0     $ 246.0     $ 166.0  
Senior note issuances (net of repayments)
    (9.4 )     (9.4 )     298.5  
Net borrowings under capital lease obligations
    23.9       3.6        
Common unit offerings(1)
    101.9       58.8        
Senior subordinated unit offerings(1)
          102.6       368.3  
 
 
(1) Includes our general partner’s proportionate contribution and net of costs associated with the offering.
 
Distributions to unitholders and our general partner represent our primary use of cash in financing activities. Unless prohibited by our bank credit facility, we will distribute all available cash, as defined in our partnership agreement, within 45 days after the end of each quarter. Total cash distributions made during the last three years were as follows (in millions):
 
                         
    Years Ended December 31,  
    2008     2007     2006  
 
Common units
  $ 94.4     $ 49.8     $ 39.7  
Subordinated units
    2.8       11.9       16.1  
General partner
    41.2       24.8       20.4  
                         
Total
  $ 138.4     $ 86.5     $ 76.2  
                         
 
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 2008, 2007 and 2006 were as follows (in millions):
 
                         
    Years Ended December 31,
    2008   2007   2006
 
Increase (decrease) in drafts payable
  $ (7.4 )   $ (19.0 )   $ 18.1  
 
Working Capital Deficit.  We had a working capital deficit of $32.9 million as of December 31, 2008, primarily due to drafts payable of $21.5 million as of the same date. 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, 2008, 2007 and 2006 are due to the impact of the fluctuations discussed above.


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Off-Balance Sheet Arrangements.  We had no off-balance sheet arrangements as of December 31, 2008 and 2007.
 
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 representing limited partner interests in the Partnership 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. Due to the decreased distribution with respect to the fourth quarter of 2008, the senior subordinated series D units will automatically convert into common units on March 23, 2009 at a ratio of 1.05 common units for each senior subordinated series D unit. The senior subordinated series D units are not entitled to distributions of available cash or allocations of net income/loss from us until March 23, 2009.
 
June 2006 Sale of Senior Subordinated Series C Units.  On June 29, 2006, we issued an aggregate of 12,829,650 senior subordinated series C units representing limited partner interests in a private equity offering for net proceeds of $359.3 million. The senior subordinated series C units were issued at $28.06 per unit, which represented a discount of 25% to the market value of common units on such date. CEI purchased 6,414,830 of the senior subordinated series C units. In addition, Crosstex Energy GP, L.P. made a general partner contribution of $9.0 million in connection with this issuance to maintain its 2% general partner interest. The senior subordinated series C units automatically converted to common units February 16, 2008 at a ratio of one common unit for each senior subordinated series C unit. The senior subordinated series C units were not entitled to distributions of available cash until their conversion to common units.
 
Sources of Liquidity in 2009 and Capital Requirements
 
Historically we have been successful in accessing capital from both the equity market and financial institutions to fund the growth of our operations. However, due to the lack of liquidity in the financial and equity markets coupled with the decline in our Midstream operations, our access to capital is expected to be severely limited in 2009. We have significantly reduced our growth plans during 2009 and 2010 to operate within our existing capital structure.
 
One of the first steps we needed to accomplish to continue to operate within our existing capital structure was to amend the terms of our bank credit facility and senior secured note agreement to allow us to operate with a higher leverage ratio and a lower interest coverage ratio due to the anticipated decline in our operating income for 2009 and 2010 based on current economic conditions. We amended our bank credit facility and our senior secured note agreement in November 2008 and again in February 2009 to provide for terms that we expect will allow us to continue to operate our assets during the current difficult economic conditions. The terms of the amended agreements allow us to maintain a higher level of leverage and to maintain a lower interest coverage ratio but our interest costs will increase, our ability to incur additional indebtedness will be restricted when we are operating at higher leverage ratios and our ability to pay distributions will be prohibited until our leverage ratio is significantly lower and we repay the PIK notes. The PIK notes are due six months after the earlier of the refinancing or maturity of our bank credit facility. The terms of these agreements and our PIK notes are described more fully under “Description of Indebtedness.”


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We have lowered our distribution level from $0.63 per unit for the second quarter of 2008 to $0.50 per unit for the third quarter of 2008 and $0.25 per unit for the fourth quarter of 2008. As discussed above, the amended terms of our bank credit facility and senior secured note agreement restrict our ability to make distributions unless certain conditions are met. We do not expect that we will meet these conditions in 2009.
 
We have reduced our budgeted capital expenditures significantly for 2009. Total growth capital investments in the calendar year 2009 are currently anticipated to be approximately $100.0 million and primarily relate to capital projects in north Texas and Louisiana pursuant to contractual obligations with producers. We will use cash flow from operations and existing capacity under our bank credit facility to fund our reduced capital spending plan during 2009. Capital expenditures in future periods will be limited to cash flow from operating activities and to existing capacity under our bank credit facility. It is unlikely that we will be able to make any acquisitions based on the terms of our credit facility and our senior secured note agreement and the condition of the capital markets because we may only use Excess Proceeds, as defined under “Amendments to Credit Documents” below, from the incurrence of unsecured debt and the issuance of equity to make such acquisitions.
 
We have reduced our general and administrative expenses by reducing our work force by approximately 8.0% through the elimination of open positions and certain corporate positions and minimizing all non-essential costs. We have also reduced our operating expenses by reducing overtime and renegotiating certain contracts to reduce monthly costs and by eliminating some equipment rentals.
 
Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of December 31, 2008 is as follows (in millions):
 
                                                         
    Payments Due by Period  
    Total     2009     2010     2011     2012     2013     Thereafter  
 
Long-Term Debt
  $ 1,263.7     $ 9.4     $ 20.3     $ 816.0     $ 93.0     $ 93.0     $ 232.0  
Interest Payable on Fixed Long-Term Debt Obligations
    194.6       38.0       37.0       35.6       31.3       23.9       28.8  
Capital Lease Obligations
    32.8       3.3       3.2       3.2       3.2       3.2       16.7  
Operating Leases
    88.5       28.4       19.0       17.9       16.4       3.1       3.7  
Unconditional Purchase Obligations
    13.5       13.5                                
FIN 48 Tax Obligations
    1.6       1.3       0.1       0.1       0.1              
                                                         
Total Contractual Obligations
  $ 1,594.7     $ 93.9     $ 79.7     $ 872.8     $ 143.9     $ 123.2     $ 281.2  
                                                         
 
The above table does not include any physical or financial contract purchase commitments for natural gas.
 
The interest payable under our bank credit facility is not reflected in the above table because such amounts depend on outstanding balances and interest rates, which will vary from time to time. Based on balances outstanding and rates in effect at December 31, 2008, annual interest payments would be $30.6 million. The interest amounts also exclude estimates of the effect of our interest rate swap contracts.
 
The unconditional purchase obligations for 2009 relate to purchase commitments for equipment.


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Description of Indebtedness
 
As of December 31, 2008 and 2007, long-term debt consisted of the following (in thousands):
 
                 
    2008     2007  
 
Bank credit facility, interest based on Prime or LIBOR plus an applicable margin, interest rates at December 31, 2008 and 2007 were 6.33% and 6.71%, respectively
  $ 784,000     $ 734,000  
Senior secured notes, weighted average interest rates at December 31, 2008 and 2007 of 8.0% and 6.75%, respectively
    479,706       489,118  
                 
      1,263,706       1,223,118  
Less current portion
    (9,412 )     (9,412 )
                 
Debt classified as long-term
  $ 1,254,294     $ 1,213,706  
                 
 
Credit Facility.  In September 2007, we increased borrowing capacity under the bank credit facility to $1.185 billion. The bank credit facility matures in June 2011. As of December 31, 2008, $850.4 million was outstanding under the bank credit facility, including $66.4 million of letters of credit, leaving approximately $334.6 million available for future borrowing.
 
Obligations under the bank credit facility are secured by first priority liens on all of our 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, and rank pari passu in right of payment with the senior secured notes. The bank credit facility is guaranteed by our material subsidiaries. We may prepay all loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs), subject to certain notice requirements.
 
On November 7, 2008, we entered into the Fifth Amendment and Consent (the “Fifth Amendment”) to our credit facility with Bank of America, N.A., as administrative agent, and the banks and other parties thereto (the “Bank Lending Group”). The Fifth Amendment amended the agreement governing our credit facility to, among other things, (i) increase the maximum permitted leverage ratio we must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009, (ii) lower the minimum interest coverage ratio we must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter, (iii) permit us to sell certain assets, (iv) increase the interest rate we pay on the obligations under the credit facility and (v) lower the maximum permitted leverage ratio we must maintain if we or our subsidiaries incur unsecured note indebtedness.
 
Due to the continued decline in commodity prices and the deterioration in the processing margins, we determined that there was a significant risk that the amended terms negotiated in November 2008 would not be sufficient to allow us to operate during 2009 without triggering a covenant default under our bank credit facility and the senior secured note agreement. On February 27, 2009, we entered into the Sixth Amendment to Fourth Amended and Restated Credit Agreement and Consent (the “Sixth Amendment”) to our credit facility with the Bank Lending Group. Under the Sixth Amendment, borrowings will bear interest at our option at the administrative agent’s reference rate plus an applicable margin or LIBOR plus an applicable margin. The applicable margins for the Partnership’s interest rate and letter of credit fees vary quarterly based on the Partnership’s leverage ratio as defined by the credit facility (the “Leverage Ratio” being generally computed as total funded debt to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) and are as follows beginning February 27, 2009:
 
                                 
    Bank Reference
    LIBOR Rate
    Letter of
    Commitment
 
Leverage Ratio
  Rate Advances(a)     Advances(b)     Credit Fees(c)     Fees(d)  
 
Greater than or equal to 5.00 to 1.00
    3.00 %     4.00 %     4.00 %     0.50 %
Greater than or equal to 4.25 to 1.00 and less than 5.00 to 1.00
    2.50 %     3.50 %     3.50 %     0.50 %
Greater than or equal to 3.75 to 1.00 and less than 4.25 to 1.00
    2.25 %     3.25 %     3.25 %     0.50 %
Less than 3.75 to 1.00
    1.75 %     2.75 %     2.75 %     0.50 %


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(a) The applicable margins for the bank reference rate advances ranged from 0% to 0.25% under the bank credit facility prior to the Fifth and Sixth Amendments. The applicable margin for the bank reference rate advances was paid at the maximum rate of 2.00% under the Fifth Amendment from the November 7, 2008 until February 27, 2009.
 
(b) The applicable margins for the LIBOR rate advances ranged from 1.00% to 1.75% under the bank credit facility prior to the Fifth and Sixth Amendments. The applicable margin for the bank reference rate advances was paid at the maximum rate of 3.00% under the Fifth Amendment from the November 7, 2008 until February 27, 2009.
 
(c) The letter of credit fees ranged from 1.00% to 1.75% per annum plus a fronting fee of 0.125% per annum under the bank credit facility prior to the Fifth and Sixth Amendments. The letter of credit fees were paid at the maximum rate of 3.00% per annum in addition to the fronting fee under the Fifth Amendment from the November 7, 2008 until February 27, 2009.
 
(d) The commitment fees ranged from 0.20% to 0.375% per annum on the unused amount of the credit facility under the bank credit facility prior to the Fifth and Sixth Amendments. The commitment fees were paid at the maximum rate of 0.50% per annum under the Fifth Amendment from the November 7, 2008 until February 27, 2009.
 
The Sixth Amendment also sets a floor for the LIBOR interest rate of 2.75% per annum, which means, effective as of February 27, 2009, borrowings under the bank credit facility accrue interest at the rate of 6.75% based on the LIBOR rate in effect on such date and our current leverage ratio. Based on our forecasted leverage ratios for 2009, we expect the applicable margins to be at the high end of these ranges for our interest rate and letter of credit fees.
 
Pursuant to the Sixth Amendment, we must pay a leverage fee if we do not prepay debt and permanently reduce the banks’ commitments by the cumulative amounts of $100.0 million on September 30, 2009, $200.0 million on December 31, 2009, and $300.0 million on March 31, 2010. If we fail to meet any de-leveraging target, we must pay a leverage fee on such date, equal to the product of the total amounts outstanding under our bank credit facility and the senior secured note agreement on such date, and 1.0% on September 30, 2009, 1.0% on December 31, 2009 and 2.0% on March 31, 2010. This leverage fee will accrue on the applicable date, but not be payable until we refinance our bank credit facility.
 
Under the Sixth Amendment, the maximum Leverage Ratio (measured quarterly on a rolling four-quarter basis) is as follows:
 
  •  7.25 to 1.00 for the fiscal quarter ending March 31, 2009;
  •  8.25 to 1.00 for the fiscal quarters ending June 30, 2009 and September 30, 2009;
  •  8.50 to 1.00 for the fiscal quarter ending December 31, 2009;
  •  8.00 to 1.00 for the fiscal quarter ending March 31, 2010;
  •  6.65 to 1.00 for the fiscal quarter ending June 30, 2010;
  •  5.25 to 1.00 for the fiscal quarter ending September 30, 2010;
  •  5.00 to 1.00 for the fiscal quarter ending December 31, 2010;
  •  4.50 to 1.00 for any fiscal quarter ending March 31, 2011 through March 31, 2012; and
  •  4.25 to 1.00 for any fiscal quarter ending June 30, 2012 and thereafter.
 
The minimum cash interest coverage ratio (as defined in the agreement, measured quarterly on a rolling four-quarter basis) is as follows under the Sixth Amendment:
 
  •  1.75 to 1.00 for the fiscal quarters ending March 31, 2009;
  •  1.50 to 1.00 for the fiscal quarter ending June 30, 2009;
  •  1.30 to 1.00 for the fiscal quarter ending September 30, 2009;
  •  1.15 to 1.00 for the fiscal quarter ending December 31, 2009;
  •  1.25 to 1.00 for the fiscal quarter ending March 31, 2010;
  •  1.50 to 1.00 for the fiscal quarter ending June 30, 2010;
  •  1.75 to 1.00 for any fiscal quarter ending September 30, 2010 and December 31, 2010; and
  •  2.50 to 1.00 for any fiscal quarter ending March 31, 2011 and thereafter.


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Under the Sixth Amendment, no quarterly distributions may be paid to unitholders unless the PIK notes have been repaid and the Leverage Ratio is less than 4.25 to 1.00. If the Leverage Ratio is between 4.00 to 1.00 and 4.25 to 1.00, we may make the minimum quarterly distribution of up to $0.25 per unit if the PIK notes have been repaid. If the Leverage Ratio is less than 4.00 to 1.00, we may make quarterly distributions to unitholders from available cash as provided by our partnership agreement if the PIK notes have been repaid. The PIK notes are due six months after the earlier of the refinancing or maturity of our bank credit facility. In order to repay the PIK notes prior to their scheduled maturity, we will need to amend or refinance our bank credit facility. Based on our forecasted leverage ratios for 2009 and our near term ability to refinance our bank credit facility, we do not anticipate making quarterly distributions in 2009 other than the distribution paid in February 2009 related to fourth quarter 2008 operating results.
 
The Sixth Amendment also limits our annual capital expenditures (excluding maintenance capital expenditures) to $120.0 million in 2009 and $75.0 million in 2010 and each year thereafter (with unused amounts in any year being carried forward to the next year). It is unlikely that we will be able to make any acquisitions based on the terms of our amended credit facility and the current condition of the capital markets because we may only use a portion of the proceeds from the incurrence of unsecured debt and the issuance of equity to make such acquisitions.
 
The Sixth Amendment also eliminated the accordion in our bank credit facility, which previously had permitted us to increase commitments thereunder by certain amounts if any bank was willing to undertake such commitment increase.
 
The Sixth Amendment also revised the terms for mandatory repayment of outstanding indebtedness from asset sales and proceeds from incurrence of unsecured debt and equity issuances. Proceeds from debt issuances and from equity issuances not required to prepay indebtedness are considered to be “Excess Proceeds” under the amended bank credit agreement. We may retain all Excess Proceeds. The following table sets forth the amended prepayment terms:
 
                         
    % of Net Proceeds
    % of Net Proceeds
    % of Net Proceeds
 
    from Asset Sales
    from Debt Issuances
    from Equity Issuance
 
    Required for
    Required for
    Required for
 
Leverage Ratio*
  Repayment     Prepayment     Prepayment  
 
Greater than or equal to 4.50
    100 %     100 %     50 %
Greater or equal to 3.50 and Less Than 4.50
    100 %     50 %     25 %
Less than 3.5
    100 %     0 %     0 %
 
 
* The Leverage Ratio is to be adjusted to give effect to proceeds from debt or equity issuance and the use of such proceeds for each proportional level of Leverage Ratio.
 
The prepayments are to be applied pro rata based on total debt (including letter of credit obligations) outstanding under the bank credit agreement and the total debt outstanding under the note agreement described below. Any prepayments of advances on the bank credit facility from proceeds from asset sales, debt or equity issuances will permanently reduce the borrowing capacity or commitment under the facility in an amount equal to 100% of the amount of the prepayment. Any such commitment reduction will not reduce the banks’ $300.0 million commitment to issue letters of credit.
 
In addition, the bank credit facility contains various covenants that, among other restrictions, limit our ability to:
 
  •  incur indebtedness;
 
  •  grant or assume liens;
 
  •  make certain investments;
 
  •  sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;
 
  •  change the nature of our business;
 
  •  enter into certain commodity contracts;


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  •  make certain amendments to our or the operating partnership’s partnership agreement; and
 
  •  engage in transactions with affiliates.
 
Each of the following will be an event of default under the bank credit facility:
 
  •  failure to pay any principal, interest, fees, expenses or other amounts when due;
 
  •  failure to observe any agreement, obligation, or covenant in the credit agreement, subject to cure periods for certain failures;
 
  •  certain judgments against us or any of our subsidiaries, in excess of certain allowances;
 
  •  certain ERISA events involving us or our subsidiaries;
 
  •  bankruptcy or other insolvency events;
 
  •  a change in control (as defined in the credit agreement); and
 
  •  the failure of any representation or warranty to be materially true and correct when made.
 
If an event of default relating to bankruptcy or other insolvency events occurs, all indebtedness under our bank credit facility will immediately become due and payable. If any other event of default exists under the bank credit facility, the lenders may accelerate the maturity of the obligations outstanding under the bank credit facility and exercise other rights and remedies.
 
We are subject to interest rate risk on our credit facility and have entered into interest rate swaps to reduce this risk. See Note 13 to the financial statements for a discussion of interest rate swaps.
 
Senior Secured Notes.  We 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 we issued the following senior secured notes (dollars in thousands):
 
                             
          Interest
           
Month Issued
  Amount     Rate(1)     Maturity    
Principal Payment Terms
 
June 2003(2)
  $ 30,000       9.45 %     7 years     Quarterly payments of $1,765 from June 2006-June 2010
July 2003(2)
    10,000       9.38 %     7 years     Quarterly payments of $588 from July 2006-July 2010
June 2004
    75,000       9.46 %     10 years     Annual payments of $15,000 from July 2010-July 2014
November 2005
    85,000       8.73 %     10 years     Annual payments of $17,000 from November 2010-December 2014
March 2006
    60,000       8.82 %     10 years     Annual payments of $12,000 from March 2012-March 2016
July 2006
    245,000       8.46 %     10 years     Annual payments of $49,000 from July 2012-July 2016
                             
Total Issued
    505,000                      
Principal repaid
    (25,294 )                    
                             
Balance as of December 31, 2008
  $ 479,706                      
                             
 
 
(1) Interest rates have been adjusted to give effect to the 2% interest rate increase under the February 27, 2009 amendment described below.
 
(2) Principal repayments were $19.4 million and $5.9 million on the June 2003 and July 2003 notes, respectively.
 
On November 7, 2008, we amended our senior secured note agreement governing our senior secured notes to, among other things, (i) modify the maximum permitted leverage ratio and lower the minimum interest coverage ratio we must maintain consistent with the ratios under the Fifth Amendment to the bank credit facility, (ii) permit


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us to sell certain assets and (iii) increase the interest rate we pay on the senior secured notes. The interest rate we paid on the senior secured notes increased by 1.25% for the fourth quarter of 2008 due to this amendment.
 
The covenant and terms of default for the senior secured notes are substantially the same as the covenants and default terms under our bank credit facility, and therefore the agreement governing the senior secured notes also required amendment in 2009. On February 27, 2009, we amended our senior note agreement to (i) increase the maximum permitted leverage ratio and to lower the minimum interest coverage ratio we must maintain consistent with the ratios under the Sixth Amendment to the bank credit facility, (ii) revise the mandatory prepayment terms consistent with the terms under the Sixth Amendment to the bank credit facility, (iii) increase the interest rate we pay on the senior secured notes and (iv) provide for the payment of a leverage fee consistent with the terms of the bank credit facility. Commencing February 27, 2009 the interest rate we pay in cash on all of the senior secured notes will increase by 2.25% per annum over the comparative interest rates under the senior note agreement prior to the November and February amendments. As a result of this rate increase, the weighted average cash interest rate of the outstanding balance on the senior secured notes is approximately 9.25% as of February 2009.
 
Under the amended senior secured notes agreement, the senior secured notes will accrue additional interest of 1.25% per annum of the senior secured note (the “PIK notes”) in the form of an increase in the principal amount unless our leverage ratio is less than 4.25 to 1.00 as of the end of any fiscal quarter. All PIK notes will be payable six months after the maturity of our bank credit facility, which is currently scheduled to mature in June 2011, or six months after refinancing of such indebtedness if prior to the maturity date.
 
Per the terms of the amended senior notes agreement, commencing on the date we refinance our bank credit facility, the interest rate payable in cash on our senior secured notes will increase by 1.25% per annum for any quarter if our leverage ratio as of the most recently ended fiscal quarter was greater than or equal to 4.25 to 1.00. In addition, commencing on June 30, 2012, the interest rate payable in cash on our senior secured notes will increase by 0.50% per annum for any quarter if our leverage as of the most recently ended fiscal quarter was greater than or equal to 4.00 to 1.00, but this incremental interest will not accrue if we are paying the incremental 1.25% per annum of interest described in the preceding sentence.
 
These notes represent our senior secured obligations and will rank pari passu in right of payment with the bank credit facility. The notes are secured, on an equal and ratable basis with our obligations under the credit facility, by first priority liens on all of our material pipeline, gas gathering and processing assets, all material working capital assets and a pledge of all our equity interests in substantially all of our subsidiaries. The senior secured notes are guaranteed by our material subsidiaries.
 
The senior secured notes issued in 2003 are redeemable, at our option and subject to certain notice requirements, at a purchase price equal to 100% of the principal amount together with accrued interest, plus a make-whole amount determined in accordance with the senior secured note agreement. The senior secured notes issued in 2004, 2005 and 2006 provide for a call premium of 103.5% of par beginning three years after issuance at rates declining from 103.5% to 100.0%. The notes are not callable prior to three years after issuance.
 
If an event of default resulting from bankruptcy or other insolvency events occurs, the senior secured notes will become immediately due and payable. If any other event of default occurs and is continuing, holders of at least 50.1% in principal amount of the outstanding notes may at any time declare all the notes then outstanding to be immediately due and payable. If an event of default relating to the nonpayment of principal, make-whole amounts or interest occurs, any holder of outstanding notes affected by such event of default may declare all the notes held by such holder to be immediately due and payable.
 
The senior secured note agreement relating to the notes contains substantially the same covenants and events of default as our bank credit facility.
 
We were in compliance with all debt covenants at December 31, 2008 and 2007 and expect to be in compliance with debt covenants for the next twelve months.
 
Intercreditor and Collateral Agency Agreement.  In connection with the execution of the senior secured note agreement, the lenders under our bank credit facility and the purchasers of the senior secured notes have entered into an Intercreditor and Collateral Agency Agreement, which has been acknowledged and agreed to by us and our


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subsidiaries. This agreement appointed Bank of America, N.A. to act as collateral agent and authorized Bank of America to execute various security documents on behalf of the lenders under our bank credit facility and the purchasers of the senior secured notes. This agreement specifies various rights and obligations of lenders under our bank credit facility, holders of our senior secured notes and the other parties thereto in respect of the collateral securing the Partnership’s obligations under our bank credit facility and the senior secured note agreement. On February 27, 2009, the holders of the Partnership’s senior secured notes and a majority of the banks under its bank credit facility entered into an amendment to the Intercreditor and Collateral Agency Agreement, which provides that the PIK notes and certain treasury management obligations will be secured by the collateral for its bank credit facility and the senior secured notes, but only paid with proceeds of collateral after obligations under its bank credit facility and the senior secured notes are paid in full.
 
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 has experienced an increase in labor and material costs during the 2007 year and the first half of 2008, although 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
 
On November 15, 2007, Crosstex Processing received a demand letter from Denbury asserting a claim for breach of contract and seeking payment of approximately $11.4 million in damages. The claim arises from a contract under which Crosstex Processing processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex Processing breached the Processing Contract by failing to build a processing plant of a certain size and design, resulting in Crosstex Processing’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex Processing failed to provide specific notices required under the Processing Contract. On December 4, 2007 and again on February 14, 2008, Denbury sent Crosstex Processing letters demanding that its claim be arbitrated pursuant to an arbitration provision in the Processing Contract. On April 15, 2008, the parties mediated the matter unsuccessfully. On December 4, 2008, Denbury initiated formal arbitration proceedings against Crosstex Processing, Crosstex Energy Services, L.P., Crosstex North Texas


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Gathering, L.P., and Crosstex Gulf Coast Marketing, Ltd., seeking $11.4 million and additional unspecified damages. On December 23, 2008, Crosstex Processing filed an answer denying Denbury’s allegations and a counterclaim seeking a declaratory judgment that its processing plant is uneconomic pursuant to the terms of the Processing Contract, allowing cancellation of the contract. Crosstex Energy, Crosstex Marketing, and Crosstex Gathering also filed an answer denying Denbury’s allegations and asserting that they are improper parties as Denbury’s claim is for breach of the Processing Contract and none of these entities is a party to that agreement. Crosstex Gathering also filed a counterclaim seeking approximately $40.0 million in damages for the value of the NGLs it is entitled to under its Gas Gathering Agreement with Denbury. Once the three-person arbitration panel has been named and cleared conflicts, the arbitration panel will hold a preliminary conference with the parties to set a date for the final hearing and other case deadlines and to establish discovery limits. Although it is not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse effect on our consolidated results of operations or financial position.
 
The Partnership (or its subsidiaries) is defending eleven lawsuits filed by owners of property located near processing facilities or compression facilities constructed by us as part of our systems in north Texas. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. At this time, five cases are set for trial during 2009. The remaining cases have not yet been set for trial. Discovery is underway. Although it is not possible to predict the ultimate outcomes of these matters, we do not believe that these claims will have a material adverse impact on our 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 $2.2 million for July 2008 sales. We believe the July sales of $2.2 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 approximately $2.2 million but the allowance of the administrative claim status is still subject to approval of the bankruptcy court in accordance with the administrative claim allowance procedures order in the case. We evaluated these receivables for collectability and provided a valuation allowance of $3.1 million during 2008.
 
Recent Accounting Pronouncements
 
In October 2008, as a result of the recent credit crisis, the FASB issued FSP No. FAS 157-3,Determining the Fair Value of a Financial Asset in a Market That is Not Active” (“FSP FAS 157-3”). FSP FAS 157-3 clarifies the application of SFAS No. 157 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. FSP FAS 157-3 is effective upon issuance, for companies that have adopted SFAS No. 157. The Partnership has evaluated the FSP and determined that this standard has no impact on its results of operations, cash flows or financial position for this reporting period.
 
In June 2008, the Financial Accounting Standards Board (“FASB”) issued Staff Position FSP EITF 03-6-1 (the “FSP”) which requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128,” and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128, Earnings per Share. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Upon adoption, the Partnership will consider restricted units with nonforfeitable distribution rights in the calculation of earnings per unit and will adjust all prior reporting periods retrospectively to conform to the requirements, although the impact should not be material.
 
In February 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment to FASB Statement No. 115” (“SFAS 159”). SFAS 159 permits entities to choose to measure many financial assets and financial liabilities at fair value. Changes in the fair value on items for


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which the fair value option has been elected are recognized in earnings each reporting period. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes elected for similar types of assets and liabilities. SFAS 159 was adopted effective January 1, 2008 and did not have a material impact on our financial statements.
 
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date, except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests and provide other disclosures required by SFAS 160.
 
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS No. 162”). SFAS No. 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States of America. SFAS No. 162 is effective for fiscal years beginning after November 15, 2008. The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 162 on our consolidated financial statements.
 
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under SFAS 133 and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The principal impact to the Partnership will be to require expanded disclosure regarding derivative instruments.
 
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.


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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. Our primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, we are also exposed to the risk of changes in interest rates on our floating rate debt.
 
Interest Rate Risk
 
We are exposed to interest rate risk on our variable rate bank credit facility. At December 31, 2008 and 2007, our bank credit facility had outstanding borrowings of $784.0 million and $734.0 million, respectively, which approximated fair value. We manage a portion of our interest rate exposure on our variable rate debt by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. In January 2008, we amended our existing interest rate swaps covering $450.0 million of the variable rate debt to extend the period by one year (coverage periods end from November 2010 through October 2011) and reduce the interest rates to a range of 4.38% to 4.68%. In September 2008, we entered into additional interest rate swaps covering the $450.0 million that converted the floating rate portion of the original swaps from three month LIBOR to one month LIBOR. In addition, we entered into one new interest rate swap in January 2008 covering $100.0 million of the variable rate debt for a period of one year at an interest rate of 2.83%. As of December 31, 2008, the fair value of these interest rate swaps was reflected as a liability of $35.5 million ($17.1 million in net current liabilities and $18.4 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 $22.4 million. Considering the interest rate swaps and the amount outstanding on our bank credit facility as of December 31, 2008, we estimate that a 1% increase or decrease in the interest rate would change our annual interest expense by approximately $2.3 million for periods when the entire portion of the $550.0 million of interest rate swaps are outstanding and $7.8 million for annual periods after 2011 when all the interest rate swaps lapse.
 
At December 31, 2008 and 2007, we had total fixed rate debt obligations of $479.7 million and $489.1 million, respectively, consisting of our senior secured notes with a weighted average interest rate of 8.0%. The fair value of these fixed rate obligations was approximately $374.4 million and $500.5 million as of December 31, 2008 and 2007, respectively. We estimate that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rated debt (our senior secured notes) by $15.2 million based on the debt obligations as of December 31, 2008.
 
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. We currently process gas under three main types of contractual arrangements:
 
1. Processing margin contracts:  Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, we 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 treated or conditioned.


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Gas processing margins by contract types, gathering and transportation margins and treating margins as a percent of total gross margin for the comparative year-to-date periods are as follows:
 
                 
    Years Ended December 31,  
    2008     2007  
 
Gathering and transportation margin
    49.3 %     41.5 %
Gas processing margins:
               
Processing margin
    17.0 %     18.4 %
Percent of liquids
    14.2 %     19.6 %
Fee based
    7.5 %     8.1 %
                 
Total gas processing
    38.7 %     46.1 %
Treating margin
    12.0 %     12.4 %
                 
Total
    100.0 %     100.0 %
                 
 
We have hedges in place at December 31, 2008 covering liquids volumes we expect to receive under percent of liquids (POL) contracts as set forth in the following table. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).
 
                                     
        Notional
              Fair Value
 
Period
  Underlying   Volume   We Pay     We Receive     Asset/(Liability)  
    (In thousands)  
 
January 2009-December 2009
  Ethane     114 (MBbls)     Index     $ 0.760 - $0.8275/gal     $ 1,751  
January 2009-December 2009
  Propane     113 (MBbls)     Index     $ 1.39 - $1.46/gal       3,577  
January 2009-December 2009
  Iso Butane     31 (MBbls)     Index     $ 1.7375 - $1.78/gal       1,222  
January 2009-December 2009
  Normal Butane     37 (MBbls)     Index     $ 1.705- $1.765/gal       1,475  
January 2009-December 2009
  Natural Gasoline     86 (MBbls)     Index     $ 2.1275-$2.1575/gal       4,553  
                                     
                                $ 12,578  
                                     
 
We have hedged our exposure to declines in prices for NGL volumes produced for our account. The NGL volumes hedged, as set forth above, focus on our POL contracts. We hedge our POL exposure based on volumes we consider hedgeable (volumes committed under contracts that are long term in nature) versus total POL volumes that include volumes that may fluctuate due to contractual terms, such as contracts with month to month processing options. We have hedged 44% of our hedgeable volumes at risk through the end of 2009 (20% of total volumes at risk through the end of 2009). We currently have not hedged any of our processing margin volumes for 2009.
 
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 transport services. Approximately 4.0% 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. We have hedged 34% of our natural gas volumes at risk through the end of 2009.


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Set forth in the table below is the volume of the natural gas purchased and sold at a fixed discount or premium to the index price and at a percentage discount or premium to the index price for our principal gathering and transmission systems and for our commercial services business for the year ended December 31, 2008.
 
                                 
    Years Ended December 31, 2008  
    Gas Purchased     Gas Sold  
    Fixed
          Fixed
       
    Amount
    Percentage of
    Amount
    Percentage of
 
Asset or Business
  to Index     Index     to Index     Index  
    (In thousands of MMBtu’s)  
 
LIG system(2)
    248,715       3,955       252,670        
South Texas system(1)
    124,888       11,892       126,969        
North Texas system
    84,311       4,577       88,339        
Other assets and activities(1)
    78,373       2,160       15,456        
 
 
1) Gas sold is less than gas purchased due to production of NGLs on some of the assets included in the south Texas system and other assets.
 
2) LIG plants purchase the gathering system plant thermal reduction (PTR).
 
Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of natural gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of natural gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.
 
Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a risk management committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas and NGLs using over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our risk management committee.
 
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.
 
As of December 31, 2008, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $16.0 million. The aggregate effect of a hypothetical 10% increase in gas and NGLs prices would result in a decrease of approximately $1.4 million in the net fair value asset of these contracts as of December 31, 2008.
 
Item 8.   Financial Statements and Supplementary Data
 
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required by this Item are set forth on pages F-1 through F-47 of this Report and are incorporated herein by reference.
 
Item 9.   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.   Controls and Procedures
 
(a)   Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy, GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act


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Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission.
 
(b)   Changes in Internal Control Over Financial Reporting
 
There has been no change in our internal controls over financial reporting that occurred in the three months ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
 
Internal Control Over Financial Reporting
 
See “Management’s Report on Internal Control over Financial Reporting” on page F-2.
 
Item 9B.   Other Information
 
On February 27, 2009, we entered into the Sixth Amendment to our Fourth Amended and Restated Credit Agreement and Consent with Bank of America, N.A. and the other lenders party thereto (the “Credit Agreement Amendment”) and Letter Amendment No. 4 to our Amended and Restated Note Purchase Agreement with the holders of our senior secured promissory notes and other parties thereto (the “Note Purchase Agreement Amendment”). We have filed the Credit Agreement Amendment and the Note Purchase Agreement Amendment as Exhibits 10.6 and 10.11, respectively, to this Form 10-K. See “Item 1. Business — Amendments to Credit Documents” and Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Description of Indebtedness” for more information.
 
PART III
 
Item 10.   Directors, Executive Officers and Corporate Governance
 
As is the case with many publicly traded partnerships, we do not have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Crosstex Energy GP, LLC. Our operational personnel are employees of the Operating Partnership. References to our general partner, unless the context otherwise requires, includes Crosstex Energy GP, LLC. References to our officers, directors and employees are references to the officers, directors and employees of Crosstex Energy GP, LLC or the Operating Partnership.
 
Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders, as limited by our partnership agreement. As general partner, Crosstex Energy GP, L.P. is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.


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The following table shows information for the directors and executive officers of Crosstex Energy GP, LLC. Executive officers and directors serve until their successors are duly appointed or elected.
 
             
Name
 
Age
 
Position with Crosstex Energy GP, LLC
 
Barry E. Davis
    47     President, Chief Executive Officer and Director
Robert S. Purgason
    52     Executive Vice President — Chief Operating Officer
William W. Davis
    55     Executive Vice President and Chief Financial Officer
Joe A. Davis
    48     Executive Vice President, General Counsel and Secretary
Rhys J. Best**
    62     Chairman of the Board and Member of the Conflicts Committee and Compensation Committee
Leldon E. Echols**
    53     Director and Member of the Audit Committee*
Bryan H. Lawrence
    66     Director
Sheldon B. Lubar**
    79     Director and Member of the Governance Committee*
Cecil E. Martin**
    67     Director and Member of the Audit Committee and Compensation Committee*
Kyle D. Vann**
    61     Director and Member of the Conflicts Committee* and Audit Committee
 
 
* Denotes chairman of committee.
 
** Denotes independent director.
 
Barry E. Davis, President, Chief Executive Officer and Director, led the management buyout of the midstream assets of Comstock Natural Gas, Inc. in December 1996, which transaction resulted in the formation of our predecessor. Mr. Davis has served as director since our initial public offering in December 2002. Mr. Davis was President and Chief Operating Officer of Comstock Natural Gas and founder of Ventana Natural Gas, a gas marketing and pipeline company that was purchased by Comstock Natural Gas. Mr. Davis started Ventana Natural Gas in June 1992. Prior to starting Ventana, he was Vice President of Marketing and Project Development for Endevco, Inc. Before joining Endevco, Mr. Davis was employed by Enserch Exploration in the marketing group. Mr. Davis holds a B.B.A. in Finance from Texas Christian University. Mr. Davis also serves as the Chairman of the Board for Crosstex Energy, Inc.
 
Robert S. Purgason, Executive Vice President — Chief Operating Officer, joined Crosstex in October 2004 as Senior Vice President — Treating Division to lead the Treating Division and was promoted to Executive Vice President — Chief Operating Officer in November 2006. Prior to joining Crosstex, Mr. Purgason spent 19 years with Williams Companies in various senior business development and operational roles. He was most recently Vice President of the Gulf Coast Region Midstream Business Unit. Mr. Purgason began his career at Perry Gas Companies in Odessa working in all facets of the treating business. Mr. Purgason received a B.S. degree in Chemical Engineering with honors from the University of Oklahoma.
 
William W. Davis, Executive Vice President and Chief Financial Officer, joined our predecessor in September 2001, and has over 25 years of finance and accounting experience. For more than the last six years Mr. Davis has served as our Chief Financial Officer. Prior to joining our predecessor, Mr. Davis held various positions with Sunshine Mining and Refining Company from 1983 to September 2001, including Vice President — Financial Analysis from 1983 to 1986, Senior Vice President and Chief Accounting Officer from 1986 to 1991 and Executive Vice President and Chief Financial Officer from 1991 to 2001. In addition, Mr. Davis served as Chief Operating Officer in 2000 and 2001. Mr. Davis graduated magna cum laude from Texas A&M University with a B.B.A. in Accounting and is a Certified Public Accountant. Mr. Davis is not related to Barry E. Davis or Joe A. Davis.
 
Joe A. Davis, Executive Vice President, General Counsel and Secretary, joined Crosstex in October 2005. He began his legal career with the Dallas firm of Worsham Forsythe, which merged with the international law firm of Hunton & Williams in 2002. Most recently, he served as a partner in the firm’s Energy Practice Group, and served on the firm’s Executive Committee. Mr. Davis specialized in facility development, sales, acquisitions and financing for the energy industry, representing entrepreneurial start up/development companies, growth companies, large


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public corporations and large electric and gas utilities. He received his J.D. from Baylor Law School in Waco and his B.S. degree from the University of Texas in Dallas. Mr. Davis is not related to Barry E. Davis or William W. Davis.
 
Rhys J. Best joined Crosstex Energy GP, LLC as a director in June 2004 and became Chairman of the Board in February 2009. Mr. Best was Chairman and Chief Executive Officer of Lone Star Technologies, Inc., until its merger into United States Steel Company in June of 2007. Mr. Best held the position of Chief Executive Officer from June 1998 and he assumed the additional responsibilities of Chairman in January 1999. He began his career at Lone Star as the President and Chief Executive Officer of Lone Star Steel Company, a position he held for eight years before becoming President and Chief Operating Officer of the parent company in 1997. Before joining Lone Star, Mr. Best held several leadership positions in the banking industry. Mr. Best also serves on the boards of Trinity Industries (NYSE: TRN), Austin Industries, Inc., and McJunkin Red Man Corporation. Trinity is a leading diversified holding company with a subsidiary group that provides a variety of products and services for the transportation, industrial, construction and energy sectors. Austin Industries and McJunkin Red Man are private companies in the construction and energy sectors. Mr. Best graduated from the University of North Texas with a Bachelor of Business degree and later earned a Masters of Business Administration Degree at Southern Methodist University.
 
Leldon E. Echols joined Crosstex Energy GP, LLC as a director in January 2008. Mr. Echols is a private investor. Mr. Echols also currently serves as an independent director of Trinity Industries, Inc. (NYSE: TRN), a leading diversified holding company with a subsidiary group that provides a variety of products and services for the transportation, industrial, construction and energy sectors, and Holly Corporation (NYSE: HOC), an independent petroleum refiner and marketer. Mr. Echols brings 30 years of financial and business experience to Crosstex. After 22 years with the accounting firm Arthur Andersen LLP, which included serving as managing partner of the firm’s audit and business advisory practice in North Texas, Colorado and Oklahoma, Mr. Echols spent six years with Centex Corporation as executive vice president and chief financial officer. He retired from Centex Corporation in June 2006. Mr. Echols is also a member of the boards of directors of two private companies, Roofing Supply Group Holdings, Inc. and Colemont Corporation. He also served on the board of TXU Corp. (NYSE: TXU) where he chaired the Audit Committee and was a member of the Strategic Transactions Committee until the completion of the private equity buyout of TXU in October 2007. Mr. Echols earned a Bachelor of Science degree in accounting from Arkansas State University and is a Certified Public Accountant. He is a member of the American Institute of Certified Public Accountants and the Texas Society of CPAs. Mr. Echols has also served as a director of Crosstex Energy, Inc. since January 2008.
 
Bryan H. Lawrence, joined Crosstex Energy GP, LLC as a director upon the completion of our initial public offering in December 2002 and served as Chairman of the Board until May 2008. Mr. Lawrence is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships, which make investments in companies engaged in the energy industry. The Yorktown partnerships were formerly affiliated with the investment firm of Dillon, Read & Co. Inc., where Mr. Lawrence had been employed since 1966, serving as a Managing Director until the merger of Dillon Read with SBC Warburg in September 1997. Mr. Lawrence also serves as a director of Hallador Petroleum Company (OTC BB: HPCO.OB), Star Gas Partners L.P. (NYSE: SGU), Winstar Resources Ltd. (a Canadian public company), Approach Resources, Inc. (NASDAQ: AREX) and certain non-public companies in the energy industry in which Yorktown partnerships hold equity interests. Mr. Lawrence is a graduate of Hamilton College and also has an M.B.A. from Columbia University.
 
Sheldon B. Lubar joined Crosstex Energy GP, LLC as a director upon the completion of our initial public offering in December 2002. Mr. Lubar has been Chairman of the Board of Lubar & Co. Incorporated, a private investment and venture capital firm he founded, since 1977. He was Chairman of the Board of Christiana Companies, Inc., a logistics and manufacturing company, from 1987 until its merger with Weatherford International in 1995. Mr. Lubar also serves as a director of Weatherford International, Inc. (NYSE: WFT), an energy services company, and Approach Resources, Inc. (NASDAQ: AREX). Mr. Lubar has also served as a director of Crosstex Energy, Inc. since January 2004. Mr. Lubar holds a bachelor’s degree in Business Administration and a Law degree from the University of Wisconsin — Madison. He was awarded an honorary Doctor of Commercial Science degree from the University of Wisconsin — Milwaukee.


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Cecil E. Martin, Jr., joined Crosstex Energy GP, LLC as a director in January 2006. He has been an independent residential and commercial real estate investor since 1991. From 1973 to 1991 he served as chairman of the public accounting firm Martin, Dolan and Holton in Richmond, Virginia. He began his career as an auditor at Ernst and Ernst. He holds a B.B.A. degree from Old Dominion University and is a Certified Public Accountant. Mr. Martin also serves on the board and as chairman of the audit committee for Comstock Resources, Inc. (NYSE:CRK), a growing independent energy company engaged in oil and gas acquisitions, exploration and development. Mr. Martin also has served as a director of Crosstex Energy, Inc. since January 2006.
 
Kyle D. Vann joined Crosstex Energy GP, LLC as a director in April 2006. Mr. Vann began his career with Exxon Corporation in 1969. After ten years at Exxon, he joined Koch Industries and served in various leadership capacities, including senior vice president from 1995 to 2000. In 2001, he then took on the role of CEO with Entergy-Koch, LP, a profitable energy trading and transportation company, which was sold in 2004. Currently, Mr. Vann, who is retired, continues to consult with Entergy and Texon, L.P. He also serves on the boards of Texon, L.P. and Legacy Reserves, LLC. Mr. Vann graduated from the University of Kansas with a Bachelor of Science degree in chemical engineering. He is a member of the Board of Advisors for the University of Kansas School of Engineering. Mr. Vann also serves on the board of various charitable organizations.
 
Independent Directors
 
Messrs. Best, Echols, Lubar, Martin, and Vann qualify as “independent” directors in accordance with the published listing requirements of The NASDAQ Stock Market (NASDAQ). The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by the NASDAQ rules, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
 
In addition, the members of the Audit Committee also each qualify as “independent” under special standards established by the SEC for members of audit committees, and the Audit Committee includes at least one member who is determined by the board of directors to meet the qualifications of an “audit committee financial expert” in accordance with SEC rules, including that the person meets the relevant definition of an “independent” director. Messrs. Echols and Martin are both independent directors who have been determined to be audit committee financial experts. Unitholders should understand that this designation is a disclosure requirement of the SEC related to experience and understanding with respect to certain accounting and auditing matters. The designation does not impose any duties, obligations or liability that are greater than are generally imposed on a member of the Audit Committee and board of directors, and the designation of a director as an audit committee financial expert pursuant to this SEC requirement does not affect the duties, obligations or liability of any other member of the Audit Committee or board of directors.
 
Board Committees
 
The board of directors of Crosstex Energy GP, LLC, has, and appoints the members of, standing Audit, Compensation, Governance and Conflicts Committees. Each member of the Audit, Compensation, Governance and Conflicts Committees is an independent director in accordance with NASDAQ standards described above. Each of the board committees has a written charter approved by the board. Copies of the charters will be provided to any person, without charge, upon request. Contact Denise LeFevre at 214-721-9245 to request a copy of a charter or send your request to Crosstex Energy, L.P., Attn: Denise LeFevre, 2501 Cedar Springs, Dallas, Texas 75201.
 
The Audit Committee, comprised of Messrs. Echols (chair), Martin and Vann, assists the board of directors in its general oversight of our financial reporting, internal controls and audit functions, and is directly responsible for the appointment, retention, compensation and oversight of the work of our independent auditors.
 
The Conflicts Committee, comprised of Messrs. Vann (chair) and Best, reviews specific matters that the board believes may involve conflicts of interest between our general partner and Crosstex Energy, L.P. The Conflicts Committee determines if the resolution of a conflict of interest is fair and reasonable to us. The members of the Conflicts Committee are not officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders.


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The Compensation Committee, comprised of Messrs. Martin (chair) and Best, oversees compensation decisions for the officers of the General Partner as well as the compensation plans described herein.
 
The Governance Committee, comprised of Mr. Lubar (chair), reviews matters involving governance including assessing the effectiveness of current policies, monitoring industry developments, developing director selection criteria, recommending director nominees, recommending committee structures within the Board, managing the assessment process of the Board and individual directors, annually reviewing and recommending the compensation of directors and performing other duties as delegated from time to time.
 
Code of Ethics
 
Crosstex Energy GP, LLC, has adopted a Code of Business Conduct and Ethics applicable to all of our employees, officers and directors with regard to Partnership-related activities. The Code of Business Conduct and Ethics incorporates guidelines designed to deter wrongdoing and to promote honest and ethical conduct and compliance with applicable laws and regulations. It also incorporates expectations of our employees that enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. A copy of our Code of Business Conduct and Ethics will be provided to any person, without charge, upon request. Contact Denise LeFevre at 214-721-9245 to request a copy of the Code or send your request to Crosstex Energy, L.P., Attn: Denise LeFevre, 2501 Cedar Springs, Dallas, Texas 75201. If any substantive amendments are made to the Code of Business Conduct and Ethics or if we or Crosstex Energy GP, LLC grant any waiver, including any implicit waiver, from a provision of the Code to any of our general partner’s executive officers and directors, we will disclose the nature of such amendment or waiver in a report on Form 8-K.
 
Section 16(a) — Beneficial Ownership Reporting Compliance
 
Based on our records, except as set forth below, we believe that during 2008 all reporting persons complied with the Section 16(a) filing requirements applicable to them. Due to administrative errors, Form 4s reporting withholding of units by Crosstex Energy, L.P. to cover tax obligations on the vesting of restricted units were filed late on behalf of Barry E. Davis, William W. Davis, Jack M. Lafield, Robert S. Purgason and Susan J. McAden on January 29, 2008; a Form 3 was filed late on behalf of Leldon E. Echols on January 30, 2008; Form 4s reporting grants of restricted units were filed late on behalf of Rhys J. Best, Kyle D. Vann, James C. Crain, Leldon E. Echols, Cecil E. Martin Jr., and Sheldon B. Lubar on July 25, 2008; Form 4s reporting the lapse of restricted units upon leaving the Crosstex Energy GP, LLC Board of Directors were filed late on behalf of Robert F. Murchison and James C. Crain on October 16, 2008; and a Form 4 reporting the withholding of units by Crosstex Energy, L.P. to cover tax obligations on the vesting of restricted units was filed late on behalf of Joe A. Davis on November 12, 2008.
 
Reimbursement of Expenses of our General Partner and its Affiliates
 
Our general partner does not receive any management fee or other compensation in connection with its management of Crosstex Energy, L.P. However, our general partner performs services for us and is reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.
 
Item 11.   Executive Compensation
 
Compensation Discussion and Analysis
 
We do not directly employ any of the persons responsible for managing our business. Crosstex Energy GP, LLC, the general partner of our general partner, manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors, officers and employees of Crosstex Energy GP, LLC is determined by the Compensation Committee of the board of directors of Crosstex Energy GP, LLC. Our named executive officers also serve as executive officers of Crosstex Energy, Inc. and the compensation of the named executive officers discussed below reflects total compensation for services to all Crosstex entities. We reimburse all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides


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that our general partner will determine the expenses allocable to us in any reasonable manner determined by our general partner in its sole discretion. Crosstex Energy, Inc. currently pays a monthly fee to us to cover its portion of administrative and compensation costs, including compensation costs relating to the named executive officers.
 
Based on the information that we track regarding the amount of time spent by each of our named executive officers on business matters relating to Crosstex Energy, L.P., we estimate that such officers devoted the following percentage of their time to the business of Crosstex Energy, L.P. and to Crosstex Energy, Inc., respectively, for 2008:
 
                 
    Percentage of Time
    Percentage of Time
 
    Devoted to
    Devoted to
 
    Business of
    Business of
 
Executive Officer or Director
  Crosstex Energy, L.P.     Crosstex Energy, Inc.  
 
Barry E. Davis
    83 %     17 %
Jack M. Lafield*
    100 %     0 %
William W. Davis
    74 %     26 %
Robert S. Purgason
    100 %     0 %
Joe A. Davis
    88 %     12 %
 
 
* Mr. Lafield departed from his position as Executive Vice President-Corporate Development with Crosstex Energy GP, LLC effective January 16, 2009.
 
Crosstex Energy GP, LLC’s Compensation Committee assists the board of directors in discharging its responsibilities relating to compensation of executive officers and has overall responsibility for approval, evaluation and oversight of all compensation plans, policies and programs of Crosstex Energy GP, LLC. Each member of the Crosstex Energy GP, LLC’s Compensation Committee is an independent director in accordance with NASDAQ standards. The responsibilities of Crosstex Energy GP, LLC’s Compensation Committee, as stated in its charter, include the following:
 
  •  reviewing and making recommendations to the board of directors, on at least an annual basis, with respect to general compensation policies of Crosstex Energy GP, LLC relating to all officers and other key executives;
 
  •  reviewing and making recommendations to the board of directors, on at least an annual basis, for the annual base salary, award of options, awards under incentive compensation and equity-based plans, employment agreements, severance agreements, and change in control agreements and any special or supplemental benefits for senior executives;
 
  •  reviewing and making recommendations to the board of directors with respect to goals and objectives relevant to the compensation of senior executives, evaluating the senior executives’ performance in light of these goals and objectives and recommending compensation levels based on this evaluation; and
 
  •  reviewing and reassessing the adequacy of the Compensation Committee’s charter, on at least an annual basis, and recommending any proposed changes to the board of directors.
 
Compensation Philosophy and Policies.  The primary objectives of Crosstex Energy GP, LLC’s compensation program, including compensation of the named executive officers, are to attract and retain highly qualified officers, employees and directors and to reward individual contributions to our success. Crosstex Energy GP, LLC considers the following policies in determining the compensation of the named executive officers:
 
  •  total compensation is related to performance of the individual executive and the performance of the executive’s division/executive team (measured against both financial and non-financial goals);
 
  •  incentive compensation represents a significant portion of the executive’s total compensation;
 
  •  compensation levels are designed to be competitive to ensure that we will be able to attract and motivate highly qualified executive officers;
 
  •  payments under retention plans are designed to retain highly qualified officers during challenging times;
 
  •  incentive compensation balances long and short-term performance achievement; and
 
  •  compensation is related to improving unitholder value.


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Compensation Methodology.  The elements of Crosstex Energy GP, LLC’s compensation program for named executive officers are intended to provide a total incentive package designed to drive performance and reward contributions in support of business strategies at the entity and individual performance. All compensation determinations are discretionary and, as noted above, subject to the decision-making authority of Crosstex Energy GP, LLC.
 
Compensation Consultant .  In 2008, Crosstex Energy GP, LLC’s Compensation Committee retained Mercer Human Resource Consulting (“Mercer”) as its independent compensation consultant to conduct a compensation study and advise the Compensation Committee on certain matters relating to compensation programs applicable to the named executive officers and other employees of Crosstex Energy GP, LLC. Mercer provided a presentation to the Compensation Committee regarding the compensation programs of the Crosstex entities in February 2008.
 
With respect to compensation objectives and decisions regarding the named executive officers the Compensation Committee has reviewed market data with respect to peer companies provided by Mercer in determining relevant compensation levels and compensation program elements for our named executive officers, including establishing base salaries, for fiscal 2008. Mercer has provided guidance on current industry best practices to the Compensation Committee. The market data that we reviewed included the base salaries paid to executive officers in similar positions at our peer companies, as well as a comparison of the mix of total compensation (including base salary, bonus structure, bonus methodology and short and long-term compensation elements) paid to executive officers in similar positions at such companies. For 2008, our peer companies consisted of the following: Energy Transfer Partners, L.P., Enbridge Energy Partners, L.P., ONEOK Partners, L.P., Southern Union, Magellan Midstream Holdings, L.P., NuStar Energy, L.P., Copano Energy, LLC, Regency Energy Partners, L.P., MarkWest Energy Partners, L.P., Boardwalk Pipeline Partners, L.P., Atmos Energy Corporation, El Paso Corporation, Questar Corporation, Equitable Resources, Inc., Pioneer Natural Resources Company, Plains Exploration & Production Company, Cabot Oil & Gas Corporation, St. Mary Land & Exploration Company and Range Resources Corporation. We believe that this group of companies is representative of the industry in which we operate and the individual companies were chosen because of such companies’ relative position in our industry, their relative size/market capitalization, the relative complexity of the business, similar organizational structure and the named executive officers’ roles and responsibilities.
 
In addition, the Compensation Committee has reviewed various relevant compensation surveys with respect to determining compensation for the named executive officers. In determining the long-term incentive component of compensation of the senior executives of Crosstex Energy GP, LLC (including the named executive officers), the Compensation Committee considers the performance and relative equity holder return, the value of similar incentive awards to senior executives at comparable companies, awards made to the company’s senior executives in past years and such other factors as the Compensation Committee deems relevant.
 
With respect to bonus amounts and stock awards paid to our chief executive officer, the bonus and incentive award amounts differ in value from awards made to our other named executive officers because the scope of our chief executive officer’s responsibilities are broader than those of our other named executive officers. In addition, our Compensation Committee considers the bonus and stock awards paid to similar named executive officers by our peer companies, which awards are generally higher for chief executive officers at our peer companies than for other executive officers at our peer companies.
 
Elements of Compensation.  The primary elements of Crosstex Energy GP, LLC’s compensation program are a combination of annual cash and long-term equity-based compensation. For fiscal year 2008, the principal elements of compensation for the named executive officers were the following:
 
  •  base salary;
 
  •  annual cash bonus plan awards;
 
  •  long-term incentive plan awards; and
 
  •  retirement and health benefits.
 
Base Salary .  Crosstex Energy GP, LLC’s Compensation Committee establishes base salaries for the named executive officers based on the historical salaries for services rendered to Crosstex Energy GP, LLC and its


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affiliates, market data and responsibilities of the named executive officers. Salaries are generally determined by considering the employee’s performance and prevailing levels of compensation in areas in which a particular employee works. As discussed above, except with respect to the monthly reimbursement payment received from Crosstex Energy, Inc., all of the base salaries of the named executive officers were allocated to us by Crosstex Energy GP, LLC as general and administration expenses. The base salaries paid to our named executive officers during fiscal year 2008 are shown in the Summary Compensation Table on page 85.
 
Each of the named executive officers, including Barry E. Davis, Jack M. Lafield, William W. Davis, Robert S. Purgason and Joe A. Davis have entered into employment agreements with Crosstex Energy GP, LLC. Mr. Lafield’s employment agreement was replaced with a separation agreement with his departure on January 16, 2009. All of these employment agreements are substantially similar, with certain exceptions as set forth below. Each of the employment agreements has a term of one year that will automatically be extended such that the remaining term of the agreements will not be less than one year. The employment agreements provide for a base annual salary of $435,000, $315,000, $300,000 and $285,000 for Barry E. Davis, William W. Davis, Robert S. Purgason and Joe A. Davis, respectively, as of January 1, 2009.
 
The employment agreements also provide for a noncompetition period that will continue until the later of one year after the termination of the employee’s employment or the date on which the employee is no longer entitled to receive payments under the employment agreement. During the noncompetition period, the employees are generally prohibited from engaging in any business that competes with us or our affiliates in areas in which we conduct business as of the date of termination and from soliciting or inducing any of our employees to terminate their employment with us.
 
Annual Cash Bonus Plan Awards.  Crosstex Energy GP, LLC’s Compensation Committee awarded cash bonus awards to each of the named executive officers in 2008. Crosstex uses financial and operational goals, as well as individual performance goals, to determine the amount of cash bonus awards that we pay to our named executive officers. Bonuses have been generally based on return on invested capital (“ROI”), bottom-line profitability, customer satisfaction, overall company growth, corporate governance, adherence to policies and procedures and other factors that vary depending on an employee’s responsibilities. The calculation of ROI is reviewed by the Board and includes adjustments for capital expenditures that are not yet deployed in income producing activities and other similar matters. With certain exceptions, approximately two-thirds of the bonuses payable to our named executive officers for fiscal 2008 were based upon a formula that is tied to ROI achieved by us during the year. If a predetermined ROI is accomplished, then the bonus is paid and is increased or decreased based on the ROI percentage that is achieved, with minimum payouts of 10%, target payouts ranging from 65% to 100%, and maximum payouts ranging from 130% to 200% of an executive officer’s base salary. Target ROI is based upon a standard of reasonable market expectations and company performance, and varies from year to year. Several factors are reviewed in determining target ROI, including market expectations, internal forecasts and available investment opportunities. For 2008, our ROI targets for bonuses were 9% for minimum bonuses, 11% for mid-point bonuses and 13% for maximum bonuses. We slightly exceeded the minimum ROI threshold of 9% with an ROI of 9.2% for 2008.
 
The remaining amount of the bonuses payable to our named executive officers for fiscal 2008 were determined in the discretion of the Compensation Committee, based upon the Compensation Committee’s assessment of performance objectives. These performance objectives include the quality of leadership within the named executive officer’s assigned area of responsibility, the achievement of technical and professional proficiencies by the named executive officer, the execution of identified priority objectives by the named executive officer and the named executive officer’s contribution to, and enhancement of, the desired company culture. These performance objectives are reviewed and evaluated by our Compensation Committee as a whole. All of our named executive officers met or exceeded their personal performance objectives for 2008.
 
For 2009, the Board has approved a modification to the Annual Cash Bonus Plan to substitute earnings before interest, income taxes, depreciation and amortization, or EBITDA, as the performance metric in place of ROI. Under the revised 2009 plan, bonuses will be determined based on EBITDA levels ranging from a threshold of $195.0 million to a maximum of $280.0 million, with a mid-point EBITDA of $225.0 million. Payout of any such bonuses will be contingent on the Partnership’s compliance with all long term debt covenants. The discretionary


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portion of the bonus will operate in the same manner as in 2008. In addition, the Board has approved a Key Employee Retention Plan for 2009 that will include each of the named executive officers and certain other members of senior management. Under the plan, participants will receive retention payments in quarterly installments equal to 20% of base salary for the first three quarters of the year and 40% of base salary for the fourth quarter, provided that the participant is employed by the Partnership at the time of payment. In the case of a participant who is terminated by Crosstex without cause, such participant will receive a prorated payment based on time of employment. Payments made under this plan will be in lieu of payments that would otherwise be payable to a participant under the Annual Cash Bonus Plan up to the mid-point EBITDA of $225.0 million. The Key Employee Retention Plan is designed to retain and compensate certain key employees that are very important for the accomplishment of the Partnership’s objectives during critical times. Participation in the plan is at the discretion of the Compensation Committee and the Board.
 
Long-Term Incentive Plans.  We compensate our employees and directors with grants from long-term incentive plans adopted by each of Crosstex Energy GP, LLC and Crosstex Energy, Inc. A discussion of each plan follows:
 
Crosstex Energy GP, LLC Long-Term Incentive Plan.  Crosstex Energy GP, LLC has adopted a long-term incentive plan for employees and directors of Crosstex Energy GP, LLC and its affiliates who perform services for us. The long-term incentive plan is administered by Crosstex Energy GP, LLC’s Compensation Committee and permits the grant of awards covering an aggregate of 4,800,000 common units, which may be awarded in the form of restricted units or unit options. Of the 4,800,000 common units that may be awarded under the long-term incentive plan, 1,915,696 common units remain eligible for future grants by Crosstex Energy GP, LLC as of January 1, 2009. The long-term compensation structure is intended to align the employee’s performance with long-term performance for our unitholders.
 
Crosstex Energy GP, LLC’s board of directors in its discretion may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Crosstex Energy GP, LLC’s board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the approval requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
 
  •  Unit Options.  The long-term incentive plan currently permits the grant of options covering common units. Under current policy all unit option grants will have an exercise price equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of us or our general partner, as discussed below under “— Potential Payments Upon a Change of Control or Termination.” Upon exercise of a unit option, Crosstex Energy GP, LLC will acquire common units in the open market or directly from us or any other person or use common units already owned, or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds received by it from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Crosstex Energy GP, LLC will pay us the proceeds it received from the optionee upon exercise of the unit option. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
 
  •  Restricted Units.  A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. In the future, the Compensation Committee may make grants under the plan to employees and directors containing such terms as it shall determine under the plan. The Compensation Committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units will vest upon a change of control of us or of our general partner, as discussed below under “— Potential Payments Upon a Change of Control or Termination.” Common units to be


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  delivered upon the vesting of restricted units may be common units acquired by Crosstex Energy GP, LLC in the open market, common units already owned by Crosstex Energy GP, LLC, common units acquired by Crosstex Energy GP, LLC directly from us or any other person or any combination of the foregoing. Crosstex Energy GP, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to restricted units which entitles the grantee to distributions attributable to the restricted units prior to vesting of such units. We intend the issuance of the common units upon vesting of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, under current policy, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
 
  •  Performance Units.  A performance unit represents a contractual commitment to grant restricted units in the future if certain conditions are satisfied. It is contemplated that performance unit agreements will only be entered into with members of our senior management. Under the terms of the performance unit agreements, to be eligible to receive the restricted units, the executive officer must continuously be employed from the date of the agreement through January 1 of the third calendar year following such date, and no units will be credited to an award recipient under our long term incentive plan until such future date. Each agreement provides for a target number of units that are to be granted in the future. The target number of units will be increased (up to a maximum of 200% of the target number of units for performance units granted in 2007 and up to a maximum of 300% for performance units granted in 2008) or decreased (to a minimum of 30% of the target number of units) based on Crosstex Energy, L.P.’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per unit) compared to the target growth rate established in the applicable performance unit agreement which will vary from year to year. In 2007 and 2008 the target growth rate was 10.5%, and 9.0%, respectively. Generally, the restricted units that are granted pursuant to a performance unit agreement will vest and become unrestricted as of March 1 of the year of vesting if the executive officer remains an employee through such date.
 
On an aggregate basis, in the past the Crosstex entities generally have granted equity compensation in a amount of up to 300% of the chief executive officer’s base salary and up to 200% of each other named executive officer’s base salary. The total value of the equity compensation granted to our named executive officers generally has been allocated 50% in restricted units of Crosstex Energy, L.P. and 50% in restricted stock of Crosstex Energy, Inc. For fiscal year 2008, Crosstex Energy GP, LLC granted 61,985, 28,499, 29,924, 28,499 and 27,074 performance units at target to Barry E. Davis, Jack M. Lafield, William W. Davis, Robert S. Purgason and Joe A. Davis, respectively. All performance and restricted units that we grant are charged against earnings according to SFAS No. 123R.
 
Crosstex Energy, Inc. Long-Term Incentive Plan.  The objectives of Crosstex Energy, Inc.’s long-term incentive plan are to attract able persons to enter the employ of the company, to encourage employees to remain in the employ of the company, to provide motivation to employees to put forth maximum efforts toward the continued growth, profitability and success of the company by providing incentives to such persons through the ownership and/or performance of Crosstex Energy, Inc.’s common stock and to attract able persons to become directors of the company and to provide such individuals with incentive and reward opportunities. Awards to participants under the long-term incentive plan may be made in the form of stock options or restricted stock awards.
 
The Crosstex Energy, Inc. long-term incentive plan provides for the award of stock options and restricted stock (collectively, “Awards”) for up to 4,590,000 shares of Crosstex Energy, Inc.’s common stock. As of January 1, 2009, approximately 626,453 shares remained available under the long-term incentive plan for future issuance to participants. A participant may not receive in any calendar year options relating to more than 100,000 shares of common stock. The maximum number of shares set forth above are subject to appropriate adjustment in the event of a recapitalization of the capital structure of Crosstex Energy, Inc. or reorganization of Crosstex Energy, Inc. Shares of common stock underlying Awards that are forfeited, terminated or expire unexercised become immediately available for additional Awards under the long-term incentive plan.


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The Compensation Committee of Crosstex Energy, Inc.’s board of directors administers the long-term incentive plan. The administrator has the power to determine the terms of the options or other awards granted, including the exercise price of the options or other awards, the number of shares subject to each option or other award, the exercisability thereof and the form of consideration payable upon exercise. In addition, the administrator has the authority to grant waivers of long-term incentive plan terms, conditions, restrictions and limitations, and to amend, suspend or terminate the plan, provided that no such action may affect any share of common stock previously issued and sold or any option previously granted under the plan without the consent of the holder. Awards may be granted to employees, consultants and outside directors of Crosstex Energy, Inc.
 
The Compensation Committee of Crosstex Energy, Inc. will determine the type or types of Awards made under the plan and will designate the individuals who are to be the recipients of Awards. Each Award may be embodied in an agreement containing such terms, conditions and limitations as determined by the Compensation Committee of Crosstex Energy, Inc. Awards may be granted singly or in combination. Awards to participants may also be made in combination with, in replacement of, or as alternatives to, grants or rights under the plan or any other employee benefit plan of the company. All or part of an Award may be subject to conditions established by the Compensation Committee of Crosstex Energy, Inc., including continuous service with the company.
 
  •  Stock Options.  Stock options are rights to purchase a specified number of shares of common stock at a specified price. An option granted pursuant to the plan may consist of either an incentive stock option that complies with the requirements of section 422 of the Code, or a nonqualified stock option that does not comply with such requirements. Only employees may receive incentive stock options and such options must have an exercise price per share that is not less than 100% of the fair market value of the common stock underlying the option on the date of grant. Nonqualified stock options also must have an exercise price per share that is not less than the fair market value of the common stock underlying the option on the date of grant. The exercise price of an option must be paid in full at the time an option is exercised.
 
  •  Restricted Stock Awards.  Stock awards consist of restricted shares of common stock of Crosstex Energy, Inc. The Compensation Committee of Crosstex Energy, Inc. will determine the terms, conditions and limitations applicable to any restricted stock awards. Rights to dividends or dividend equivalents may be extended to and made part of any stock award at the discretion of the Crosstex Energy, Inc. Compensation Committee. Restricted stock awards will have a vesting period established in the sole discretion of the Compensation Committee, provided that the Compensation Committee may provide for earlier vesting by reason of death, disability, retirement or otherwise.
 
  •  Performance Shares.  A performance share represents a contractual commitment to grant restricted shares in the future if certain conditions are satisfied. It is contemplated that performance share agreements will only be entered into with members of our senior management. Under the terms of the performance share agreements, to be eligible to receive the restricted shares, the executive officer must continuously be employed from the date of the agreement through January 1 of the third calendar year following such date, and no shares will be credited to an award recipient under our long term incentive plan until such future date. Each agreement provides for a target number of shares that are to be granted in the future. The target number of shares will be increased (up to a maximum of 200% of the target number of shares for performance units granted in 2007 and up to a maximum of 300% for performance units granted in 2008) or decreased (to a minimum of 30% of the target number of shares) based on Crosstex Energy, L.P.’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit) compared to the target growth rate established in the applicable performance shares agreement which will vary from year to year. In 2007 and 2008, the target growth rate was 10.5% and 9%, respectively. Generally, the restricted shares that are granted pursuant to a performance share agreement will vest and become unrestricted as of March 1 of the year of vesting if the executive officer remains an employee through such date.
 
Crosstex Energy, Inc.’s board of directors may amend, modify, suspend or terminate the long-term incentive plan for the purpose of addressing any changes in legal requirements or for any other purpose permitted by law, except that no amendment that would impair the rights of any participant to any Award may be made without the consent of such participant, and no amendment requiring stockholder approval under any


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applicable legal requirements will be effective until such approval has been obtained. No incentive stock options may be granted after the tenth anniversary of the effective date of the plan.
 
In the event of any corporate transaction such as a merger, consolidation, reorganization, recapitalization, separation, stock dividend, stock split, reverse stock split, split up, spin-off or other distribution of stock or property of Crosstex Energy, Inc., the Crosstex Energy, Inc. board of directors shall substitute or adjust, as applicable: (i) the number of shares of common stock reserved under this plan and the number of shares of common stock available for issuance pursuant to specific types of Awards as described in the plan, (ii) the number of shares of common stock covered by outstanding Awards, (iii) the grant price or other price in respect of such Awards and (iv) the appropriate fair market value and other price determinations for such Awards, in order to reflect such transactions, provided that such adjustments shall only be such that are necessary to maintain the proportionate interest of the holders of Awards and preserve, without increasing, the value of such Awards.
 
As discussed above, on an aggregate basis, in the past the Crosstex entities generally have granted equity compensation in a amount of up to 300% of the chief executive officer’s base salary and up to 200% of each other named executive officer’s base salary. The total value of the equity compensation granted to our executive officers generally has been awarded 50% in restricted units of Crosstex Energy, L.P. and 50% in restricted stock of Crosstex Energy, Inc. In addition, our executive officers may receive additional grants of equity compensation in certain circumstances, such as promotions. For fiscal year 2008, Crosstex Energy, Inc. granted 58,748, 27,011, 28,361, 27,011 and 25,660 performance shares at target to Barry E. Davis, Jack M. Lafield, William W. Davis, Robert S. Purgason and Joe A. Davis, respectively. All performance and restricted shares that we grant are charged against earnings according to SFAS No. 123R.
 
Retirement and Health Benefits.  Crosstex Energy GP, LLC offers a variety of health and welfare and retirement programs to all eligible employees. The named executive officers are generally eligible for the same programs on the same basis as other employees of Crosstex Energy GP, LLC. Crosstex Energy GP, LLC maintains a tax-qualified 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantages basis. In 2008, Crosstex Energy GP, LLC matched 100% of every dollar contributed for contributions of up to 6% of salary (not to exceed the maximum amount permitted by law) made by eligible participants. The retirement benefits provided to the named executive officers were allocated to us as general and administration expenses. Our executive officers are also eligible to participate in any additional retirement and health benefits available to our other employees.
 
Perquisites and Other Compensation.  Crosstex Energy GP, LLC generally does not pay for perquisites for any of the named executive officers, other than payment of dues, sales tax and related expenses for membership in an industry related private lunch club (totaling less than $2,500 per year per person).
 
Compensation Mix.  Crosstex Energy GP, LLC’s Compensation Committee determines the mix of compensation, both among short and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of the named executive officers. We believe that the mix of base salary, cash bonus awards, awards under the long-term incentive plan, retirement and health benefits and perquisites and other compensation fit our overall compensation objectives. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies that we require.
 
Potential Payments Upon a Change of Control or Termination.
 
Employment Agreements.  Under the employment agreements with our executive officers, we may be required to pay certain amounts upon a change of control of us or our affiliates or upon the termination of the executive officer in certain circumstances. Except in the event of our becoming bankrupt or ceasing operations, termination for cause or termination by the employee other than for good reason, or if a change in control occurs during the term of an employee’s employment and either party to the agreement terminates the employee’s employment as a result thereof, the employment agreements entered into between Crosstex Energy GP, LLC and each of the named executive officers provide for continued salary payments, bonus and benefits following termination of employment for the remainder of the employment term under the agreement. The terms contained


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in the employment agreements were established at the time we entered into such agreements with our named executive officers. These terms were determined based on past practice and our understanding of similar agreements utilized by public companies generally at the time we entered into such agreements. The determination of the reasonable consequences of a change of control is periodically reviewed by the Compensation Committee. For purposes of the employment agreements:
 
  •  “Cause” means that:
 
  •  the employee has failed to perform the duties assigned to him and such failure has continued for 30 days following delivery by Crosstex Energy GP, LLC of written notice to the employee of such failure;
 
  •  the employee has been convicted of a felony or misdemeanor involving moral turpitude;
 
  •  the employee has engaged in acts or omissions against Crosstex Energy GP, LLC constituting dishonesty, breach of fiduciary obligation or intentional wrongdoing or misfeasance;
 
  •  the employee has acted intentionally or in bad faith in a manner that results in a material detriment to the assets, business or prospects of Crosstex Energy GP, LLC; or
 
  •  the employee has breached any obligation under the employment agreement.
 
  •  “Good reason” includes any of the following:
 
  •  the assignment to employee of any duties materially inconsistent with the employee’s position (including a materially adverse change in the employee’s office, title and reporting requirements), authority, duty or responsibilities;
 
  •  Crosstex Energy GP, LLC requiring the employee to be based at any office other than the offices in the greater Dallas, Texas area;
 
  •  any termination by Crosstex Energy GP, LLC of the employee’s employment other than as expressly permitted by the employment agreement; or
 
  •  a breach or violation by Crosstex Energy GP, LLC of any material provision of the employment agreement, which breach or violation remains unremedied for more than 30 days after written notice thereof is given to Crosstex Energy GP, LLC by the employee.
 
  •  No act or failure to act on Crosstex Energy GP, LLC’s part shall be considered “good reason” unless the employee has given Crosstex Energy GP, LLC written notice of such act or failure to act within 30 days thereof and Crosstex Energy GP, LLC fails to remedy such act or failure to act within 30 days of its receipt of such notice.
 
  •  A “change in control” shall be deemed to have occurred if:
 
  •  Crosstex Energy, Inc. and/or its affiliates, collectively, no longer directly or indirectly hold a controlling interest in Crosstex Energy GP, L.P. or Crosstex Energy GP, LLC and the named executive officer does not remain employed by Crosstex Energy GP, LLC upon the occurrence of such event (whether the employee’s employment is terminated voluntarily or by Crosstex Energy GP, LLC);
 
  •  the consummation of any transaction as a result of which any person (other than Yorktown Partners LLC, a Delaware limited liability company, or its affiliates including any funds under its management) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Securities Exchange Act of 1934, as amended), directly or indirectly, of at least 50% of the total voting power represented by the outstanding voting securities of Crosstex Energy, Inc. at a time when Crosstex Energy, Inc. still beneficially owns 50% or more of the voting power of the outstanding equity interests of Crosstex Energy GP, L.P. or Crosstex Energy GP, LLC; or
 
  •  Crosstex Energy GP, LLC has caused the sale of at least 50% of our assets.


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If a termination of a named executive officer by Crosstex Energy GP, LLC other than for cause, a termination by a named executive officer for good reason or upon a change in control were to have occurred as of December 31, 2008, our named executive officers would have been entitled to the following:
 
  •  Barry E. Davis would have received $435,000 representing base salary for the remainder of the term of the employment agreement (i.e., one year’s salary paid at regularly scheduled times), $78,000 representing bonuses earned under any incentive plans in which he is a participant earned up to the date of termination or change in control and continued participation in Crosstex Energy GP, LLC’s health plans for the remainder of the term of the employment agreement;
 
  •  Robert S. Purgason would have received $300,000 representing base salary for the remainder of the term of the employment agreement (i.e., one year’s salary paid at regularly scheduled times), $45,000 representing bonuses earned under any incentive plans in which he is a participant earned up to the date of termination or change in control and continued participation in Crosstex Energy GP, LLC’s health plans for the remainder of the term of the employment agreement;
 
  •  Jack M. Lafield would have received $300,000 representing base salary for the remainder of the term of the employment agreement (i.e., one year’s salary paid at regularly scheduled times), $45,000 representing bonuses earned under any incentive plans in which he is a participant earned up to the date of termination or change in control and continued participation in Crosstex Energy GP, LLC’s health plans for the remainder of the term of the employment agreement;
 
  •  William W. Davis would have received $315,000 representing base salary for the remainder of the term of the employment agreement (i.e., one year’s salary paid at regularly scheduled times), $147,000 representing bonuses earned under any incentive plans in which he is a participant earned up to the date of termination or change in control and continued participation in Crosstex Energy GP, LLC’s health plans for the remainder of the term of the employment agreement; and
 
  •  Joe A. Davis would have received $285,000 representing base salary for the remainder of the term of the employment agreement (i.e., one year’s salary paid at regularly scheduled times), $43,000 representing bonuses earned under any incentive plans in which he is a participant earned up to the date of termination or change in control and continued participation in Crosstex Energy GP, LLC’s health plans for the remainder of the term of the employment agreement.
 
Long-Term Incentive Plan.  With respect to the Long-Term Incentive Plans, the amounts to be received by our named executive officers in these circumstances will be automatically determined based on the number of unvested stock or unit awards or restricted stock or units held by a named executive officer at the time of a change in control. The terms of the Long-Term Incentive Plans were determined based on past practice and our understanding of similar plans utilized by public companies generally at the time we adopted such plans. The determination of the reasonable consequences of a change of control is periodically reviewed by the Compensation Committee.
 
Crosstex Energy GP, LLC Long-Term Incentive Plan.  Under current policy, if a grantee’s employment is terminated for any reason other than death or disability, depending on the particular terms of the agreement in question, a grantee’s unit options and restricted units granted under the long-term incentive plan may automatically be forfeited unless, and to the extent, the Compensation Committee provides otherwise. With respect to performance units, however, in the case of a termination without cause or for good reason, the pro-rata portion of the number of units that have accrued to the date of termination will vest and become payable to the participant. A grantee’s options, restricted units and performance units will generally vest in the event of death or disability. Upon a change in control of us or our general partner, all unit options, restricted units and performance units will automatically vest and become payable or exercisable, as the case may be, in full and any restricted periods or performance criteria shall terminate or be deemed to have been achieved at the maximum level. For purposes of the long-term incentive plan, a “change in control” means, and shall be deemed to have occurred if:
 
  •  the consummation of a merger or consolidation of Crosstex Energy GP, LLC with or into another entity or any other transaction if persons who were not holders of equity interests of Crosstex Energy GP, LLC immediately prior to such merger, consolidation or other transaction, 50% or more of the voting power of the outstanding equity interests of the continuing or surviving entity;


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  •  the sale, transfer or other disposition of all or substantially all of Crosstex Energy GP, LLC’s or our assets;
 
  •  a change in the composition of the board of directors as a result of which fewer than 50% of the incumbent directors are directors who either had been directors of Crosstex Energy GP, LLC on the date 12 months prior to the date of the event that may constitute a change in control (the “original directors”) or were elected, or nominated for election, to the board of directors of Crosstex Energy GP, LLC with the affirmative votes of at least a majority of the aggregate of the original directors who were still in office at the time of the election or nomination and the directors whose election or nomination was previously so approved; or
 
  •  the consummation of any transaction as a result of which any person (other than Yorktown Partners LLC, a Delaware limited liability company, or its affiliates including any funds under its management) becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of Crosstex Energy, Inc. representing at least 50% of the total voting power represented by CEI’s then outstanding voting securities at a time when Crosstex Energy, Inc. still beneficially owns more than 50% of securities of Crosstex Energy GP, LLC representing at least 50% of the total voting power represented by Crosstex Energy GP, LLC’s then outstanding voting securities.
 
If a change in control were to have occurred as of December 31, 2008, unit options, restricted units and performance units held by the named executive officers would have automatically vested and become payable or exercisable, as follows:
 
  •  Barry E. Davis held 16,667 restricted units and 218,117 performance units that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
  •  Robert S. Purgason held 18,886 restricted units, 101,043 performance units and options to purchase 10,000 common units that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
  •  Jack M. Lafield held 10,145 restricted units and 101,043 performance units that would have become fully vested, payable and/or exercisable as a result of such change in control; and
 
  •  William W. Davis held 10,145 restricted units and 105,318 performance units that would have become fully vested, payable and/or exercisable as a result of such change in control.
 
  •  Joe A. Davis held 7,199 restricted units and 91,876 performance units that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
Crosstex Energy, Inc. Long-Term Incentive Plan.  Under current policy, if a grantee’s employment is terminated for any reason other than death or disability, depending on the particular terms of the agreement in question, a grantee’s options and restricted shares that have been granted may automatically be forfeited unless, and to the extent, the Compensation Committee provides otherwise. With respect to performance shares, however, in the case of a termination without cause or for good reason, the pro-rata portion of the number of shares that have accrued to the date of termination will vest and become payable to the participant. A grantee’s options, restricted shares and performance shares will generally vest in the event of death or disability. Immediately prior to a “change of control” of Crosstex Energy, Inc., all option awards, restricted stock awards and performance shares will automatically vest and become payable or exercisable, as the case may be, in full and all vesting periods will terminate. For purposes of the long-term incentive plan, a “change of control” means:
 
  •  the consummation of a merger or consolidation of Crosstex Energy, Inc. with or into another entity or any other transaction, if persons who were not shareholders of Crosstex Energy, Inc. immediately prior to such merger, consolidation or other transaction beneficially own immediately after such merger, consolidation or other transaction 50% or more of the voting power of the outstanding securities of each of (i) the continuing or surviving entity and (ii) any direct or indirect parent entity of such continuing or surviving entity;
 
  •  the sale, transfer or other disposition of all or substantially all of Crosstex Energy, Inc.’s assets;
 
  •  a change in the composition of the board of directors of Crosstex Energy, Inc. as a result of which fewer than 50% of the incumbent directors are directors who either (i) had been directors of Crosstex Energy, Inc. on the date 12 months prior to the date of the event that may constitute a change of control (the “original directors”)


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  or (ii) were elected, or nominated for election, to the board of directors of Crosstex Energy, Inc. with the affirmative votes of at least a majority of the aggregate of the original directors who were still in office at the time of the election or nomination and the directors whose election or nomination was previously so approved; or
 
  •  any transaction as a result of which any person is the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of Crosstex Energy, Inc. representing at least 50% of the total voting power represented by Crosstex Energy, Inc.’s then outstanding voting securities.
 
If a change in control were to have occurred as of December 31, 2008, options and restricted stock held by the named executive officers would have automatically vested and become payable or exercisable, and any vesting periods of restricted stock would have terminated, as follows:
 
  •  Barry E. Davis held 38,154 shares of restricted stock and 213,744 performance shares that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
  •  Robert S. Purgason held 38,631 shares of restricted stock, 98,985 performance shares and options to purchase 30,000 common shares that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
  •  Jack M. Lafield held 36,594 shares of restricted stock and 98,985 performance shares that would have become fully vested, payable and/or exercisable as a result of such change in control;
 
  •  William W. Davis 36,594 shares of restricted stock and 103,035 performance shares that would have become fully vested, payable and/or exercisable as a result of such change in control; and
 
  •  Joe A. Davis held 8,565 shares of restricted stock and 87,634 performance shares that would have become fully vested, payable and/or exercisable as a result of such change in control.
 
Role of Executive Officers in Executive Compensation.  Crosstex Energy GP, LLC’s Compensation Committee determines the compensation payable to each of the named executive officers. None of the named executive officers serves as a member of the Compensation Committee. However, our chief executive officer, Barry E. Davis, provides periodic recommendations to the Compensation Committee regarding the compensation of the other named executive officers.
 
Tax and Accounting Considerations.  The equity compensation grant policies of the Crosstex entities have been impacted by the implementation of SFAS No. 123R, which we adopted effective January 1, 2006. Under this accounting pronouncement, we are required to value unvested unit options granted prior to our adoption of SFAS 123 under the fair value method and expense those amounts in the income statement over the stock option’s remaining vesting period. As a result, the Crosstex entities currently intend to discontinue grants of unit option and stock option awards and instead grant restricted unit and restricted stock awards to the named executive officers and other employees. The Crosstex entities have structured the compensation program to comply with Internal Revenue Code Section 409A. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit includible in income. None of the named executive officers or other employees had non-performance based compensation paid in excess of the $1.0 million tax deduction limit contained in Internal Revenue Code Section 162(m).


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Summary Compensation Table
 
The following table sets forth certain compensation information for our chief executive officer and our four other most highly compensated executive officers in 2008.
 
                                                                         
                            Change in
       
                            Pension Value
       
                            and
       
                        Non-Equity
  Nonqualified
       
                        Incentive
  Deferred
       
                Stock
  Option
  Plan
  Compensation
  All Other
   
Name and
      Salary
  Bonus
  Awards
  Awards
  Compensation
  Earnings
  Compensation
  Total
Principal Position
  Year   ($)   ($)   ($)(6)   ($)   ($)   ($)   ($)   ($)
 
Barry E. Davis
    2008       435,000       78,000       1,154,104                         356,580 (1)     2,023,684  
President and Chief
    2007       400,000       400,000       1,111,409                         213,210 (1)     2,124,619  
Executive Officer
    2006       390,000       95,000       1,126,875                         167,630 (1)     1,779,505  
Robert S. Purgason
    2008       300,000       45,000       530,627                         224,589 (2)     1,100,216  
Executive Vice
    2007       290,000       226,000       534,691                         175,038 (2)     1,225,729  
President and Chief
    2006       222,385       47,500       1,392,025                         113,267 (2)     1,775,177  
Operating Officer
                                                                       
Jack M. Lafield
    2008       300,000       45,000       530,627                         211,951 (3)     1,087,578  
Executive Vice
    2007       290,000       226,000       534,691                         222,622 (3)     1,273,313  
President
    2006       275,000       60,000       685,926                         198,061 (3)     1,218,987  
William W. Davis
    2008       315,000       147,000       557,137                         220,452 (4)     1,239,589  
Executive Vice
    2007       290,000       226,000       534,691                         227,411 (4)     1,278,102  
President and Chief
    2006       275,000       60,000       685,926                         198,061 (4)     1,218,987  
Financial Officer
                                                                       
Joe A. Davis
    2008       285,000       43,000       504,085                         234,324 (5)     1,066,409  
Executive Vice
    2007       265,000       226,000       366,422                         137,440 (5)     994,862  
President and
    2006       250,000       47,500       549,967                         86,349 (5)     933,816  
General Counsel
                                                                       
 
 
(1) Amount of all other compensation for Mr. Barry Davis includes distributions on restricted units and performance units of Crosstex Energy, L.P. in the amount of $192,471 in 2008, $123,134 in 2007 and $95,251 in 2006, and dividends on restricted stock and performance shares of Crosstex Energy, Inc. in the amount of $139,374 in 2008, $83,308 in 2007 and $62,755 in 2006.
 
(2) Amount of all other compensation for Mr. Purgason includes distributions on restricted units and performance units of Crosstex Energy, L.P. in the amount of $112,788 in 2008, $66,202 in 2007 and $18,520 in 2006, and dividends on restricted stock and performance shares of Crosstex Energy, Inc. in the amount of $87,873 in 2008, $64,097 in 2007 and $37,260 in 2006.
 
(3) Amount of all other compensation for Mr. Lafield includes distributions on restricted units and performance units of Crosstex Energy, L.P. in the amount of $96,430 in 2008, $113,048 in 2007 and $97,211 in 2006, and dividends on restricted stock and performance shares of Crosstex Energy, Inc. in the amount of $91,709 in 2008, $106,806 in 2007 and $93,438 in 2006.
 
(4) Amount of all other compensation for Mr. William Davis includes distributions on restricted units and performance units of Crosstex Energy, L.P. in the amount of $98,923 in 2008, $113,048 in 2007 and $97,211 in 2006, and dividends on restricted stock and performance shares of Crosstex Energy, Inc. in the amount of $93,140 in 2008, $106,806 in 2007 and $93,438 in 2006.
 
(5) Amount of all other compensation for Mr. Joe Davis includes distributions on restricted units and performance units of Crosstex Energy, L.P. in the amount of $118,791 in 2008, $76,876 in 2007 and $47,925 in 2006, and dividends on restricted stock and performance shares of Crosstex Energy, Inc. in the amount of $91,625 in 2008, $52,988 in 2007 and $36,300 in 2006.
 
(6) The amounts shown represent the amount recognized for financial statement reporting purposes computed in accordance with Statement of Financial Accounting Standards No. 123R, “Share-Based Payment.” See Note 11 to our audited financial statements included in Item 8 herein for the assumptions made in our valuation of such awards.


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Grants of Plan-Based Awards for Fiscal Year 2008 Table
 
The following tables provide information concerning each grant of an award made to a named executive officer for fiscal year 2008, including, but not limited to, awards made under the Crosstex Energy GP, LLC Long-Term Incentive Plan and the Crosstex Energy, Inc. Long-Term Incentive Plan.
 
CROSSTEX ENERGY GP, LLC — GRANTS OF PLAN-BASED AWARDS
 
                                         
    Estimated Future Payouts Under
 
    Equity Incentive Plan Awards  
                            Grant
 
                            Date Fair
 
                            Value of
 
                            Unit
 
          Threshold
    Target
    Maximum
    Awards
 
Name
  Grant Date     (#)     (#)     (#)     ($)(1)  
 
Barry E. Davis
    3/27/08       18,596       61,985       185,955       571,455  
Robert S. Purgason
    3/27/08       8,550       28,499       85,497       262,742  
Jack M. Lafield
    3/27/08       8,550       28,499       85,497       262,742  
William W. Davis
    3/27/08       8,977       29,924       89,772       275,863  
Joe A. Davis
    3/27/08       8,122       27,074       81,222       249,589  
 
 
(1) Performance units reported at the threshold (minimum) number of units. Performance units awarded to named executive officers in 2008 included distribution rights for the target level units. See discussion of award characteristics on page 78.
 
CROSSTEX ENERGY, INC. — GRANTS OF PLAN-BASED AWARDS
 
                                         
    Estimated Future Payouts Under Equity Incentive Plan Awards  
                            Grant
 
                            Date Fair
 
                            Value of
 
                            Stock
 
          Threshold
    Target
    Maximum
    Awards
 
Name
  Grant Date     (#)     (#)     (#)     ($)(1)  
 
Barry E. Davis
    3/27/08       17,624       58,748       176,244       582,649  
Robert S. Purgason
    3/27/08       8,103       27,011       81,033       267,885  
Jack M. Lafield
    3/27/08       8,103       27,011       81,033       267,885  
William W. Davis
    3/27/08       8,508       28,361       85,083       281,274  
Joe A. Davis
    3/27/08       7,698       25,660       76,980       254,496  
 
 
(1) Performance shares reported at the threshold (minimum) number of units. Performance shares awarded to named executive officers in 2008 included dividend rights for the target level shares. See discussion of award characteristics on page 79.


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Outstanding Equity Awards at Fiscal Year-End Table for Fiscal Year 2008
 
The following tables provide information concerning all outstanding equity awards made to a named executive officer as of December 31, 2008, including, but not limited to, awards made under the Crosstex Energy GP, LLC Long-Term Incentive Plan and the Crosstex Energy, Inc. Long-Term Incentive Plan.
 
CROSSTEX ENERGY GP, LLC — OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
 
                                                                         
    Option Awards     Stock Awards  
                                                    Equity
 
                                              Equity
    Incentive
 
                                              Incentive
    Plan
 
                                              Plan
    Awards:
 
                                              Awards:
    Market
 
                                              Number
    or Payout
 
                Equity
                            of
    Value of
 
                Incentive
                            Unearned
    Unearned
 
                Plan
                            Shares,
    Shares,
 
    Number of
    Number of
    Awards:
                      Market
    Units or
    Units or
 
    Securities
    Securities
    Number of
                Number
    Value of
    Other
    Other
 
    Underlying
    Underlying
    Securities
                of Units
    Units
    Rights
    Rights
 
    Unexercised
    Unexercised
    Underlying
    Option
          That
    That
    That
    That
 
    Options
    Options
    Unexercised
    Exercise
    Option
    Have Not
    Have Not
    Have Not
    Have Not
 
    (#)
    (#)(3)
    Unearned Options
    Price
    Expiration
    Vested
    Vested
    Vested
    Vested
 
Name
  Exercisable     Unexercisable     (#)     ($)     Date     (#)     ($)(1)     (#)(2)     ($)(1)  
 
Barry E. Davis
                                  16,667       72,835       4,824 (4)     21,081  
                                                              18,596 (5)     81,265  
Robert S. Purgason
    5,000       5,000             30.00       11/15/14       18,886       82,532       2,331 (4)     10,186  
                                                              8,550 (5)     37,364  
Jack M. Lafield
                                  10,145       44,334       2,331 (4)     10,186  
                                                              8,550 (5)     37,364  
William W. Davis
                                  10,145       44,334       2,331 (4)     10,186  
                                                              8,977 (5)     39,229  
Joe A. Davis
                                  7,199       31,460       1,598 (4)     6,983  
                                                              8,122 (5)     35,493  
 
 
(1) The closing price for the common units was $4.37 as of December 31, 2008.
 
(2) Performance units reported at the threshold (minimum) number of units. See discussion on page 78.
 
(3) Options vest and become exercisable on November 5, 2009.
 
(4) Performance units vest on March 1, 2010.
 
(5) Performance units vest on M