UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

 

 

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)

 

 

(Registrant’s telephone number, including area code)

 

(214) 953-9500

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

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):

 

(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

 

 

 

 

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.

Set forth in the table below is a list of our acquisitions since January 1, 2004.

 

 

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:

 

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

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

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:

 

 

 

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

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.

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

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.

 

 

 

 

 

 

 

 

 

 

 

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

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

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

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:

 

 

 

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

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

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

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

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.

 

 

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.

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:

 

 

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

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:

 

 

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:

 

 

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.

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:

 

 

 

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.

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:

 

 

 

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

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:

 

 

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.

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:

 

 

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.

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:

 

 

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.

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

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.

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

 

 

Conflicts Relating to Costs:

 

 

 

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.

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 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

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,

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

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.

 

 

We do not have any unresolved staff comments.

 

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.

 

 

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

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.

 

 

No matters were submitted to security holders during the fourth quarter of the year ended December 31, 2008.

 

 

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.

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.

 

 

 

 

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:

 

 

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.”

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

 

 

 

 

 

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.”

 

 

 

 

 

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

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:

 

 

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:

 

 

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

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

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

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

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.

 

 

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

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:

 

 

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:

 

 

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):

 

 

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:

 

 

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

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):

 

 

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.

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):

 

 

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.

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):

 

 

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

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:

 

 

 

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):

 

 

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):

 

 

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.

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):

 

 

 

 

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):

 

 

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):

 

 

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.

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.”

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):

 

 

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.

Description of Indebtedness

 

As of December 31, 2008 and 2007, long-term debt consisted of the following (in thousands):

 

 

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:

 

 

 

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:

 

 

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:

 

 

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: