**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

**Form 10-K**
| **x**  | ** ** | **Annual Report Pursuant to Section 13 or  15(d) of the Securities Exchange Act of 1934  For the fiscal year ended December 31, 2005**                                                                                                                                                                    |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **OR** |
| o      | ** ** | **Transition Report Pursuant to  Section 13 or 15(d) of the Securities Exchange Act of 1934  For the transition period  from                             to** |

 

**Commissionfile number: 001-32329**

**COPANOENERGY, L.L.C.**

*(Exact name of registrant as specifiedin its charter)*
| **Delaware***(State of organization)*                                                             |   | **51-0411678***(I.R.S. Employer Identification No.)* |
|---------------------------------------------------------------------------------------------------|--------|------------------------------------------------------|
| **2727 Allen Parkway, Suite 1200  Houston, Texas***(Address of principal executive offices)* |   | **     77019***(Zip Code)*            |

 

**(713) 621-9547**

*(Registrant’s telephone number,including area code*

**None**

(Former name, formeraddress and former fiscal year, if changed since last report)

*SECURITIES REGISTERED PURSUANT TOSECTION 12(b) OF THE ACT:*
|      | **Title of Each Class** | ** **     | ** ** |  | **Name of Exchange on which Registered** | ** ** |
|------|-------------------------|----------------|------------|--|------------------------------------------|------------|
| None |                    | Not applicable |

 

SECURITIES REGISTEREDPURSUANT TO SECTION 12(g) OF THE ACT:

|                                                                | **Title of Class** | ** ** |
|----------------------------------------------------------------|--------------------|------------|
| Common Units  Representing Limited Liability Company Interests |

 

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

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Exchange Act. Yes o   No x

Indicate by check mark whether registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past90 days. Yes x   No o

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

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2of the Exchange Act.

Large acceleratedfiler x   Accelerated filer o   Non-accelerated filer o

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

As of June 30, 2005, the aggregate market value ofour voting and non-voting common equity held by non-affiliates of theregistrant was approximately $221.7 million based on $36.79 per unit, thelast reported sale price of the Common Units as reported on The NASDAQ NationalMarket on such date.

As of March 1, 2006, there were outstanding14,811,195 Common Units and 3,519,126 Subordinated Units.

**DOCUMENTSINCORPORATED BY REFERENCE:**
|                                                                                                                               | **Document** | ** ** | ** **    | **Parts Into Which Incorporated** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------|--------------|------------|---------------|--------------------------------------------------|------------|
| Portions of the  Proxy Statement for the Annual Meeting of Unitholders of Copano Energy,  L.L.C. to be held May 25, 2006 |         |       | Part III |                                             |       |
|                                                                                                                               |              |            |               |                                                  |            |  |  |

 

 

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**TABLE OF CONTENTS**

|          | ** ** | ** **                                                                                                         | ** ** | **Page** | ** ** |
|----------|------------|--------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
|     |       | **PART I**                                                                                                    |       |     |       |   |   |
| Item  1. |       | Business                                                                                                           |       |     | 1          |   |   |
| Item 1A. |       | Risk Factors                                                                                                       |       |     | 29         |   |   |
| Item 1B. |       | Unresolved Staff  Comments                                                                                         |       |     | 43         |   |   |
| Item 2.  |       | Properties                                                                                                         |       |     | 43         |   |   |
| Item 3.  |       | Legal Proceedings                                                                                                  |       |     | 43         |   |   |
| Item 4.  |       | Submission of  Matters to a Vote of Security Holders                                                               |       |     | 44         |   |   |
|     |       | **PART II**                                                                                                   |       |     |       |   |   |
| Item 5.  |       | Market for  Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases  of Equity Securities |       |     | 45         |   |   |
| Item 6.  |       | Selected Financial  Data                                                                                           |       |     | 49         |   |   |
| Item 7.  |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operation                         |       |     | 53         |   |   |
| Item 7A. |       | Quantitative  and Qualitative Disclosures about Market Risk                                                        |       |     | 80         |   |   |
| Item 8.  |       | Financial  Statements and Supplementary Data                                                                       |       |     | 85         |   |   |
| Item 9.  |       | Changes in and  Disagreements With Accountants on Accounting and Financial Disclosure                              |       |     | 85         |   |   |
| Item 9A. |       | Controls and  Procedures                                                                                           |       |     | 85         |   |   |
| Item 9B. |       | Other Information                                                                                                  |       |     | 89         |   |   |
|     |       | **PART III**                                                                                                  |       |     |       |   |   |
| Item 10. |       | Directors and  Executive Officers of the Registrant                                                                |       |     | 90         |   |   |
| Item 11. |       | Executive  Compensation                                                                                            |       |     | 90         |   |   |
| Item 12. |       | Security  Ownership of Certain Beneficial Owners and Management and Related Unitholder  Matters                    |       |     | 90         |   |   |
| Item 13. |       | Certain  Relationships and Related Parties                                                                         |       |     | 90         |   |   |
| Item 14. |       | Principal  Accountant Fees and Services                                                                            |       |     | 90         |   |   |
|     |       | **PART IV**                                                                                                   |       |     |       |   |   |
| Item 15. |       | Exhibits and  Financial Statement Schedules                                                                        |       |     | 91         |   |   |

 

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**PART I**

*Unless the contextrequires otherwise, references to “Copano,” “we,” “our,” “us,” or like termsrefer to Copano Energy, L.L.C. and its wholly-owned subsidiaries, includingScissorTail Energy, LLC. “ScissorTail” as used in this Annual Report refers toScissorTail Energy, LLC. “ScissorTail Acquisition” refers to our acquisition ofScissorTail on August 1, 2005.*

*As generally used in the energy industry and in thisAnnual Report, the following terms have the following meanings:*

| *$/gal:*       | * * | *U.S. dollars per gallon*                                                                                                                |
|----------------|----------|------------------------------------------------------------------------------------------------------------------------------------------|
| *Bbls:*        | * * | *Barrels*                                                                                                                                |
| *Bbls/d:*      | * * | *B**arrels per day*                                                                                                                      |
| *Btu:*         | * * | *British thermal units*                                                                                                                  |
| *Mcf:*         | * * | *One thousand cubic feet*                                                                                                                |
| *Mcf/d:*       | * * | *One thousand cubic feet per day*                                                                                                        |
| *MMBtu:*       | * * | *One million British thermal units*                                                                                                      |
| *MMcf:*        | * * | *One million cubic feet*                                                                                                                 |
| *MMBtu/d:*     | * * | *One million British thermal units per day*                                                                                              |
| *MMcf/d:*      | * * | *One million cubic feet per day*                                                                                                         |
| *NGLs:*        | * * | *Natural gas liquids which consist primarily of  ethane, propane, isobutane, normal butane, natural gasoline and stabilized  condensate* |
| *residue gas:* | * * | *The pipeline quality natural gas remaining after  natural gas is processed*                                                             |
| *throughput:*  | * * | *The volume of product transported or passing  through a pipeline, plant, terminal or other facility*                                    |

 

**Item 1.**                        Business

**General**

Copano Energy, L.L.C., a Delaware limited liabilitycompany, was formed in August 2001 to acquire entities operating under theCopano name since 1992. Since our inception in 1992, we have grown through acombination of more than 30 acquisitions and the construction of new assets. Wecompleted our initial public offering on November 15, 2004 and our commonunits are listed on The NASDAQ National Market under the symbol “CPNO.”  Our business activities are primarilyconducted through wholly-owned subsidiaries.

We are a growth-oriented midstream energycompany with natural gas gathering and intrastate transmission pipeline assetsand natural gas processing facilities in the Texas Gulf Coast region and incentral and eastern Oklahoma. Our midstream assets include over 4,700 miles ofnatural gas gathering and transmission pipelines and four natural gasprocessing plants, with approximately 800 MMcf/d of combined processingcapacity. Our Houston Central Processing Plant is the second largest naturalgas processing plant in the Texas Gulf Coast region and the third largest inTexas in terms of throughput capacity. This processing plant is locatedapproximately 100 miles southwest of Houston and has the capacity to processapproximately 700 MMcf/d of natural gas. In addition to our natural gaspipelines, we own a 104-mile NGL pipeline extending from our HoustonCentral Processing Plant to the Houston area. The pipelines we operate include144 miles of pipeline owned by Webb/Duval Gatherers (“Webb Duval”), apartnership in which we own a 62.5% interest.

Our natural gas pipelinescollect natural gas from designated points near producing wells and deliverthese volumes to third-party pipelines, our processing plants, third-partyprocessing plants, local distribution companies, power generation facilitiesand industrial consumers. Volumes delivered to our processing plants, eitherthrough our pipelines or a third-party pipeline, are treated to remove 

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contaminantsand conditioned or processed to extract mixed NGLs. Processed or conditionednatural gas is then delivered primarily to third-party pipelines through plantinterconnects, while NGLs are separated and sold to third parties.

**Recent Developments**

*Expansionof our Risk Management Program.**  *In December 2005, we expanded our commodityhedge program through our acquisition of a portfolio of natural gas andproduct-specific NGL puts and our entry into swap agreements with respect tofour NGL products. We purchased puts on natural gas through 2009 and purchasedputs and entered into swaps for ethane, propane, isobutane and normal butanethrough 2008. The hedges were executed with four investment gradecounterparties in accordance with our Risk Management Policy. Totalconsideration for the puts acquired in December was approximately $38million, funded through a combination of cash on hand and borrowings under oursenior secured revolving credit facility. The newly-acquired hedges, incombination with the crude oil puts we acquired in July 2005, wereimplemented as cash flow hedges to mitigate the impact of declines in commodityprices. For a more detailed discussion of our risk management activities,please read Item 7A “Quantitative and Qualitative Disclosures about MarketRisk.”

*PrivatePlacement of $50 Million of Common Units.**  *On December 30,2005, we announced the private placement of $50 million of common units withthree private investors, which was consummated in December 2005 and January 2006.The proceeds of the private placement were used to reduce outstandingindebtedness, including indebtedness incurred to purchase commodity hedges inconnection with the expansion of our commodity hedging program described above.

*Declarationof Distribution.**  *OnJanuary 18, 2006, our Board of Directors declared a cash distribution forthe three months ended December 31, 2005 of $0.55 per unit for alloutstanding common and subordinated units. The distribution, totaling $10.1million, was paid on February 14, 2006 to holders of record at the closeof business on February 1, 2006.

*Rule 144A SeniorNotes Offering.**  *OnFebruary 7, 2006, we issued an aggregate of $225 million in principalamount of 8.125% Senior Notes due 2016, (the “Senior Notes”), in a privateplacement exempt from the registration requirements under the Securities Act of1933, as amended (the “Securities Act”). The Senior Notes are fully andunconditionally guaranteed on an unsecured and unsubordinated basis by all ofour wholly-owned subsidiaries (the “Guarantors”). The Senior Notes were offeredand sold within the United States only to qualified institutional buyers inreliance on Rule 144A under the Securities Act, and outside the UnitedStates only to non-U.S. persons in reliance on Regulation S under theSecurities Act. The Senior Notes were issued pursuant to an indenture (the “Indenture”)among the Issuers, the Guarantors and U.S. Bank National Association, astrustee. Interest on the Senior Notes will accrue from the date of issuance orthe most recent interest payment date, and will be payable in cashsemi-annually in arrears on March 1 and September 1 of each year,commencing on September 1, 2006. For a more detailed discussion of theterms of the Senior Notes, please read Item 7 “Management’s Discussion andAnalysis of Financial Condition and Results of Operation—Liquidity and CapitalResources—Description of Our Indebtedness.”

**Business Strategy**

Our management teamis committed to improving cash flow from our existing assets, pursuingcomplementary acquisition and expansion opportunities, and managing ourcommodity risk exposure. Key elements of our strategy include:

·       *Pursue growth from our existing assets.  *Ourpipelines and processing plants have excess capacity, which provides us withopportunities to increase throughput volume with minimal incremental 

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costs. We intend toincrease cash flow from our existing assets by aggressively marketing ourservices to producers to connect new supplies of natural gas and increasevolumes and utilization.

·       *Pursue complementary acquisitions and expansionopportunities.  *We intend to use our acquisition andintegration experience to continue to make complementary acquisitions ofmidstream assets in our operating areas that provide opportunities to expandeither the acquired assets or our existing assets to increase utilization. Wepursue acquisitions that we believe will allow us to capitalize on our existinginfrastructure, personnel, and producer and customer relationships tostrengthen our existing integrated package of services. Also, we intend toexpand our assets where appropriate to meet increased demand for our midstreamservices.

·       *Reduce sensitivity of our cash flows to commodityprice fluctuations.  *Because of the volatility of natural gasand NGL prices, we attempt to structure our contracts in a manner that allowsus to achieve positive gross margins in a variety of market conditions. In ourcontracts for services provided by our Texas Gulf Coast Processing segment, wefocus on arrangements pursuant to which we are paid a fee to condition naturalgas when processing is economically unattractive. In our contracts withproducers within our Texas Gulf Coast Pipelines and Mid-Continent Operationssegments, we focus on arrangements pursuant to which the fee received for theservices we deliver is sufficient to provide us with positive operating marginsirrespective of commodity prices.

Inaddition, our commodity risk management activities are designed to hedge ourexposure to price risk and insure that we meet debt service requirements,required capital expenditures, distribution objectives and similar requirementsdespite fluctuations in commodity prices. We intend to continue to manage ourexposure to commodity prices in the future by entering into similar hedgetransactions. Please read “—Recent Developments—Expansion of our RiskManagement Program” for a discussion of our recent risk management activities.

·       *Exploit the operating flexibility of our assets.  *Exploitingour ability to condition natural gas at our Houston Central Processing Plant,rather than fully process it, provides us with significant benefits duringperiods when fully processing natural gas is not economic. We continuallymonitor natural gas and NGL prices to quickly switch between processing andconditioning modes when it is economically appropriate to do so. In addition,we will continue to utilize our ability to reject ethane at our Houston CentralProcessing Plant, Paden Plant and Glenpool Plant, as market conditions warrant.

·       *Expand ourgeographic scope into new regions where our growth strategy can be applied.  *Weintend to pursue opportunities to acquire assets in new regions where webelieve growth opportunities are attractive and our business strategies areapplicable.

**Risk Factors**

You should considercarefully the risks and uncertainties described in Item 1A “Risk Factors”and other information in this Annual Report, including Item 7 “Management’sDiscussion and Analysis of Financial Condition and Results of Operation” andour consolidated financial statements and related notes beginning on page F-1.

**Our Operations**

We present our results of operations in the followingoperating segments:

*TexasGulf Coast Pipelines Segment.**  *Our pipeline facilities in Texasare managed as four separate operating regions—the South Texas, Coastal Waters,Central Gulf Coast, and Upper Gulf Coast regions. These assets had combinedthroughput capacity of 846 MMcf/d as of December 31, 2005, including 219 

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MMcf/d of throughputcapacity owned by Webb Duval. For the year ended December 31, 2005, weaveraged net throughput volume of 322 MMcf/d of natural gas through thesepipeline assets.

*TexasGulf Coast Processing Segment.**  *Our Texas Gulf Coast Processingsegment includes our Houston Central Processing Plant located near Sheridan,Texas in Colorado County (total inlet capacity of 700 MMcf/d) and our SheridanNGL Pipeline that runs from the tailgate of the processing plant to the Houstonarea. Our Houston Central Processing Plant removes NGLs from the natural gassupplied by the Kinder Morgan Texas Pipeline (“KMTP”) Laredo-to-Katy pipeline,which it straddles, and the pipelines in our Central Gulf Coast Regiongathering systems, and separates NGLs for sale to third parties. For the yearended December 31, 2005, we averaged net natural gas throughput volume of530 MMcf/d through our Houston Central Processing Plant.

*Mid-Continent OperationsSegment (operations we acquired in the ScissorTail Acquisition).**  *The acquisition of ScissorTail hasprovided us with an operating presence in natural gas producing regions incentral and eastern Oklahoma. Our Mid-Continent Operations’ assets includeapproximately 3,300 miles of pipelines in eight primarily low-pressure gatheringsystems spanning approximately 16,900 square miles, with combined throughputcapacity of 219 MMcf/d as of December 31, 2005, and three processingplants with total inlet capacity of approximately 100 MMcf/d. For the periodfrom August 1, 2005 (the date we acquired ScissorTail) through December 31,2005, the total average throughput volumes for our Mid-Continent Operationssegment were 132 MMcf/d and average inlet volumes at our processing plants were55 MMcf/d. In addition to natural gas processed at our plants, we also delivernatural gas for processing at three third-party plants for which we receive aportion of the product revenues. Average daily throughput volumes processed atthird-party plants for ScissorTail were 33 MMcf/d for the period from August 1,2005 through December 31, 2005. Pleaseread Item 7, “Management’s Discussion and Analysis of FinancialCondition and Results of Operation—OurResults of Operation” and Note 16 to the Consolidated FinancialStatements, “Segment Information” contained in Item 8 of this AnnualReport for more detailed descriptions of the financial results of our operatingsegments.

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**OurTexas Gulf Coast Operations**

Our Texas GulfCoast Operations consist of two of our operating segments, Texas Gulf CoastPipelines and Texas Gulf Coast Processing. The following is a map of our TexasGulf Coast region assets:

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Wehave set forth in the table below summary information describing the regions inwhich we have pipeline systems and processing assets in the Texas Gulf Coastregion:

| ** **                          | ** ** | ** **                       | ** ** | ** **          | ** ** | ** **                        | ** ** | ** **          | ** ** | **Average**                                    | ** ** | **Year Ended  December 31, 2005**              | ** ** |
|-------------------------------------|------------|----------------------------------|------------|---------------------|------------|-----------------------------------|------------|---------------------|------------|------------------------------------------------|------------|---------------------------------------------------------------|------------|
| **Asset**                           | ** ** | ** **                       | ** ** | **Pipeline  Type**  | ** ** | **Initial  Acquisition  Date(1)** | ** ** | **Length  (miles)** | ** ** | **Existing  Throughput  Capacity  (Mcf/d)(2)** | ** ** | **Throughput  at Time of  Acquisition  (Mcf/d)(3)** | ** ** | **Net Average  Throughput  Volumes  (Mcf/d)** | ** ** | **Utilization  of  Capacity** | ** ** |
| **Texas Gulf Coast Pipelines**      | ** ** | ** **                       |       | ** **          | ** ** |                              | ** ** | ** **          |       |                                           | ** ** |                                                          |       | ** ** |   |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| **South Texas Region**              | ** ** | ** **                       |       | ** **          | ** ** |                              | ** ** | ** **          |       |                                           | ** ** |                                                          |       | ** ** |   |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Live Oak Area                       |       | Gathering                        |       | May 2002       | ** ** |                              | 114        | ** **          |       |                                           | 88,000     |                                                          |       | 9,179 |   |   | 18,286 | ** ** |   |   | 21 | % |   |
| Agua Dulce Area(4)                  |       | Gathering and  Transmission |       | June 1996      | ** ** |                              | 388        | ** **          |       |                                           | 78,000     |                                                          |       | 7,850 |   |   | 25,671 | ** ** |   |   | 33 | % |   |
| Hebbronville Area                   |       | Gathering                        |       | September 1994 | ** ** |                              | 79         | ** **          |       |                                           | 62,700     |                                                          |       | 15,337 |   |   | 29,643 | ** ** |   |   | 47 | % |   |
| Karnes Area                         |       | Gathering                        |       | August 2004    | ** ** |                              | 68         | ** **          |       |                                           | 17,500     |                                                          |       | 2,000 | (5) |   | 6,895 | ** ** |   |   | 39 | % |   |
| Webb/Duval Area(6)(7)               |       | Gathering                        |       | February 2002  | ** ** |                              | 144        | ** **          |       |                                           | 219,000    |                                                          |       | 43,046 |   |   | 106,826 | ** ** |   |   | 49 | % |   |
| **Coastal Waters Region**           |       | Gathering                        |       | June 1992      | ** ** |                              | 142        | ** **          |       |                                           | 37,000     |                                                          |       | 1,208 |   |   | 2,722 | ** ** |   |   | 7 | % |   |
| **Central Gulf Coast Region**  |       | Gathering                        |       | August 2001    | ** ** |                              | 231        | ** **          |       |                                           | 205,000    |                                                          |       | 118,804 |   |   | 92,872 | ** ** |   |   | 45 | % |   |
| **Upper Gulf Coast Region**         |       | Gathering and  Transmission |       | April 1997     | ** ** |                              | 230        | ** **          |       |                                           | 139,000    |                                                          |       |   |   |   | 38,685 | ** ** |   |   | 28 | % |   |
| Total                               |       |                             |       | ** **          | ** ** |                              | 1,396      | ** **          |       |                                           |       |                                                          |       |   |   |   | 321,600 | ** ** |   |   |   |   |   |
| **Texas  Gulf Coast Processing**    |       |                             |       | ** **          | ** ** |                              |       | ** **          |       |                                           |       |                                                          |       |   |   |   |   | ** ** |   |   |   |   |   |
| Houston Central Processing Plant    |       | Processing                       |       | August 2001    | ** ** |                              |       | ** **          |       |                                           |       |                                                          |       |   |   |   |   | ** ** |   |   |   |   |   |
| Inlet volumes                       |       |                             |       | ** **          | ** ** |                              |       | ** **          |       |                                           |       |                                                          |       | 626,764 | (8) |   | 530,346 | ** ** |   |   |   |   |   |
| NGLs produced                       |       |                             |       | ** **          | ** ** |                              |       | ** **          |       |                                           |       |                                                          |       | 10,406 Bbls/d | (8) |   | 13,066 | ** ** |   |   |   |   |   |
| Sheridan NGL  Pipeline              |       | NGL  Transportation              |       | August 2001    | ** ** |                              | 104        | ** **          |       |                                           |       |                                                          |       | 2,648 Bbls/d | (8) |   | 3,552 | ** ** |   |   |   |   |   |
|                                     |            |                                  |            |                     |            |                                   |            |                     |            |                                                |            |                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)             The initial acquisition date is the date that we firstcommenced operations with respect to any area, region and facility.

(2)             Many capacity values are based on current operatingconfigurations and could be increased through additional compression, increaseddelivery meter capacity and/or other facility upgrades including, for example,larger dehydration capacity.

(3)             Reflects average throughput for the first month inwhich we operated the assets.

(4)             Throughput volumes presented in the table are net ofintercompany transactions. Gross volumes and utilization of capacity in thisarea totaled 26,011 Mcf/d and 33%, respectively, for the year ended December 31,2005.

(5)             Only reflects throughput volumes on our Runge GatheringSystem that we acquired and integrated in December 2004. No historicalthroughput information is available for the Karnes County Gathering System(acquired in August 2004) as no throughput existed in the month prior toacquisition.

(6)             Our Webb/Duval Area consists of the Webb/DuvalGathering System and two smaller gathering systems, which are owned byWebb/Duval Gatherers, an unconsolidated partnership in which we hold a 62.5%interest.

(7)             Throughput volumes presented in the table are net ofaffiliate transactions. Gross volumes and utilization of capacity in this areatotaled 126,513 Mcf/d and 58%, respectively, for the year ended December 31,2005.

(8)             Represents volumes for the month of June 2001. In July 2001,volumes began to be transported from our South Texas Region to the KMTPLaredo-to-Katy pipeline thereby increasing the volume of NGLs produced by ourHouston Central Processing Plant and transported on our Sheridan NGL line.

 

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**Texas Gulf Coast Pipelines Segment**

We own approximately 1,396miles of pipelines used for natural gas gathering and transmission, includingapproximately 144 miles of pipeline owned by Webb Duval. For the years ended December 31,2005 and 2004, we averaged net throughput volumes of 321,600 Mcf/d and 325,407Mcf/d, respectively, of natural gas. Our facilities are operated in fourseparate operating regions as described below.

**South Texas Region**

The South Texas Regionconsists of eight wholly-owned gathering and intrastate transmission systemstotaling approximately 649 miles of pipelines operating in Atascosa, Bee,DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces and SanPatricio Counties, Texas. This region is composed of several operating pipelinesystems including the Live Oak System, the Clayton Pipeline, the Agua DulceSystem, the Nueces County System, the Mesteña Grande System, the HebbronvillePipeline, the Karnes County Gathering System and the Runge Gathering System.This region is managed from our field office in Alice, Texas. In addition, ouremployees in this region are responsible for the operations of Webb/DuvalGatherers, as more fully described below.

*Live Oak Area*

Our Live Oak Area is comprised of two gatheringsystems, the Live Oak System and the Clayton Pipeline.

*LiveOak System.**  *The Live Oak System is an approximately 56-milepipeline system that gathers natural gas from fields located in Live OakCounty, Texas. The Live Oak System is composed of a 12-inch diametermainline and two 8-inch diameter main gathering lateral lines, theBennett lateral and the Patteson lateral, which extend into southern andeastern Live Oak County. The system also includes several smaller lines thatrange in size from two inches to eight inches in diameter. We currently gathernatural gas from approximately 28 active receipt meters representing 18producers and four shippers connected to our Live Oak System. All of thenatural gas from the Live Oak System is compressed, dehydrated and delivered tothe KMTP Laredo-to-Katy pipeline for treating, conditioning and/or processingat our Houston Central Processing Plant.

Average throughput volume on this system was14,158 Mcf/d and 21,278 Mcf/d for the years ended December 31, 2005and 2004, respectively. In February 2002, we expanded our compression anddehydration facilities providing a throughput capacity of 50,000 Mcf/d. Wecurrently operate 1,710 horsepower of compression and 40,000 Mcf/d ofdehydration capacity.

*ClaytonPipeline.**  *The Clayton Pipeline is an approximately 58-milepipeline extending through Atascosa, Live Oak and Duval Counties, Texas. Thenorthern 34 miles consists of 10-inch diameter pipeline and the southern22 miles consists of 16-inch diameter pipeline. There are approximatelytwo miles of 3-inch to 6-inch diameter feeder pipelines. Wecurrently transport natural gas on the Clayton Pipeline from four activereceipt meters including the Pueblo Midstream Fashing plant in Atascosa County,representing four producers as well as the Fashing plant tailgate interconnect.Natural gas is delivered to either Houston Pipe Line Company or Natural GasPipeline Company of America (“NGPL”). The Clayton Pipeline has no compressionor dehydration facilities.

Average throughput volumeon the Clayton Pipeline was 4,128 Mcf/d and 2,002 Mcf/d for the yearsended December 31, 2005 and 2004, respectively. The Clayton Pipeline has acapacity of 52,000 Mcf/d.

*Agua Dulce Area*

Our Agua Dulce Area consists of two primary pipelineassets, the Agua Dulce System and the Nueces County System.

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*AguaDulce System.**  *The Agua Dulce System is an approximately247-mile gathering system located in Duval, Jim Wells and NuecesCounties, Texas. The Agua Dulce System is composed of (i) the East Duvallateral, a 17-mile, 10-inch diameter mainline that originates nearAgua Dulce, Texas in Jim Wells County, and terminates at an interconnect withthe Webb/Duval Gathering System and (ii) several distinct gatheringsystems that deliver natural gas to the East Duval lateral. There areapproximately 247 miles of 2-inch to 12-inch diameter gatheringpipelines that supply the East Duval lateral. We currently gather natural gasfrom 44 active receipt meters, representing 37 producers. Since purchasing thesystem, we have added approximately 9 miles of pipeline, including the 6-mile,12-inch diameter line that connected the system to the Webb/DuvalGathering System in 2002. We currently have 5,110 horsepower of compression and44,000 Mcf/d of dehydration capacity installed on this system. Natural gas isgathered and transported through the Agua Dulce System into the Webb/DuvalGathering System, which can deliver this natural gas into the KMTPLaredo-to-Katy pipeline. The Agua Dulce System has inactive interconnects withEnterprise Products Partners, L.P. (“Enterprise”), Humble Gas Pipeline Company(an affiliate of ExxonMobil), and Duke Energy Field Services.

Average net throughput volume on this system was20,340 Mcf/d and 22,196 Mcf/d for the years ended December 31, 2005and 2004, respectively. The Agua Dulce System has an estimated capacity of37,000 Mcf/d.

*NuecesCounty System.**  *The Nueces County System is anapproximately 141-mile pipeline system that gathers natural gas in Nuecesand San Patricio Counties, Texas. The Nueces County System is composed ofgathering and transmission lines ranging in size from two inches to 12 inchesin diameter. The Nueces County System currently gathers natural gas from 14active receipt meters representing nine producers. Natural gas from this systemis gathered and delivered to Houston Pipe Line Company (an affiliate of EnergyTransfer Partners, L.P.) and to our Agua Dulce System. We currently have 85horsepower of compression and 33,000 Mcf/d of dehydration capacity installed onthis system.

Average throughput volumeon this system was 5,331 Mcf/d and 10,203 Mcf/d for the years ended December 31,2005 and 2004, respectively. The Nueces County System has an estimated capacityof 41,000 Mcf/d under current operating pressures.

*Hebbronville Area*

There are two major pipelines that encompass theHebbronville area, the Mesteña Grande System and the Hebbronville Pipeline.

*MesteñaGrande System.**  *The Mesteña Grande System is anapproximately 56-mile pipeline system located in the southern portion ofJim Hogg County and the northern half of Duval County, Texas. The MesteñaGrande System currently gathers natural gas from 17 active receipt meters, representingfive producers and one shipper. This system consists of pipelines ranging insize from 4 inches to 8 inches in diameter. All natural gas gathered from theMesteña Grande System is transported for delivery to KMTP via our HebbronvillePipeline. We currently have 4,020 horsepower of compression installed on thissystem and 80,000 Mcf/d of dehydration capacity.

*HebbronvillePipeline.**  *The Hebbronville Pipeline was constructedby us in 2001 and is an approximately 23-mile pipeline comprised of 12-inchdiameter pipeline and 16-inch diameter pipeline, which transports all ofthe natural gas from the Mesteña Grande System for delivery to the KMTPLaredo-to-Katy pipeline. The Hebbronville Pipeline has two active receiptmeters representing one shipper. There is no installed compression ordehydration on this pipeline.

Average throughput volumeon these pipelines was 29,643 Mcf/d and 29,423 Mcf/d on a combined basisfor the years ended December 31, 2005 and 2004, respectively. The MesteñaGrande System currently has an estimated capacity of 62,700 Mcf/d and theHebbronville Pipeline has an estimated capacity of 

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250,000Mcf/d. Without additional compression, however, the combined capacity of thesepipelines is limited to 62,000 Mcf/d.

*Karnes Area*

The Karnes Area is comprised of two natural gasgathering systems, the Karnes County Gathering System and the Runge GatheringSystem.

*KarnesCounty Gathering System.**  *The Karnes County Gathering Systemis an approximately 15-mile pipeline operating in northern Bee andsouthern Karnes Counties, Texas. This system is comprised of natural gaspipelines ranging in size from 10 inches to 16 inches in diameter. The KarnesCounty Gathering System gathers natural gas from one active receipt meterconnected to a third party. Natural gas transported on the Karnes CountyGathering System is delivered to the KMTP Laredo-to-Katy pipeline and isprocessed or conditioned at our Houston Central Processing Plant. We currentlyhave 2,060 horsepower of compression installed on this system.

*RungeGathering System.**  *TheRunge Gathering System is comprised of 53 miles of natural gas pipelineslocated in Bee, DeWitt, Goliad and Karnes Counties, Texas. This system iscomprised of 37 miles of natural gas pipelines ranging in size from 4 inches to8 inches and a 16-mile 4-inch natural gas liquids pipeline that wasconverted to natural gas service to provide delivery of natural gas from theRunge Gathering System to our Karnes County Gathering System. Natural gas fromthe Runge Gathering System is gathered and redelivered into the Karnes CountyGathering System which is then delivered to the KMTP Laredo-to-Katy pipelineand is processed or conditioned at our Houston Central Processing Plant. Thissystem has six active receipt meters.

Average throughput volumeon these pipelines was 6,895 Mcf/d on a combined basis for the year ended December 31,2005. Average throughput volumes on these pipelines were 9,771 Mcf/d for theperiod from acquisition through December 31, 2004.

*Webb/Duval Area*

Our Webb/Duval Area is comprised of the Webb/DuvalGathering System, the Olmitos Gathering System and the Cinco CompadresGathering System, each of which is owned by Webb Duval, a general partnershipthat we operate and in which we hold a 62.5% interest. As the holder of a 62.5%interest in the partnership that owns these pipeline systems, we operate thesesystems subject to certain rights of the other partners, including the right toapprove capital expenditures in excess of $0.1 million, financing arrangementsby the partnership or any expansion projects associated with these systems. Inaddition, each partner has the right to use its pro rata share of pipelinecapacity on these systems subject to applicable ratable take and commonpurchaser statutes.

*Webb/DuvalSystems.**  *The Webb/Duval Gathering System is a 121-milepipeline located in Webb and Duval Counties, Texas, and is comprised of 3-inchand 16-inch diameter pipelines. Following our construction of a 6-mile,12-inch diameter pipeline in 2002, the Webb/Duval Gathering Systemconnects our Agua Dulce System to the KMTP Laredo-to-Katy pipeline. Wecurrently have 29 active receipt meters connected to the Webb/Duval GatheringSystem, representing 11 shippers. We currently have 7,468 horsepower ofinstalled compression and no dehydration on this system. The Olmitos GatheringSystem and the Cinco Compadres Gathering System are smaller non-contiguousgathering systems that are part of Webb Duval’s assets. The Olmitos GatheringSystem is a 14-mile pipeline located in Webb County, Texas, and iscomprised of 4-inch to 8-inch diameter pipelines. The CincoCompadres Gathering System is a 9-mile pipeline located in Webb County,Texas, and is comprised of 3-inch to 6-inch diameter pipelines.

Average total throughputvolume on these combined systems including volumes delivered by our Agua DulceSystem was 126,513 Mcf/d and 126,305 Mcf/d for the years ended December 31,2005 and 

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2004,respectively. Excluding the volume received from our Agua Dulce Systemdescribed previously, the average throughput volume on these systems was106,286 Mcf/d and 104,437 Mcf/d for the years ended December 31, 2005and 2004, respectively. Differences in volumes between the Webb/Duval GatheringArea and the Agua Dulce systems are attributable to gas consumed as fuel duringdehydration and compression, ordinary pipeline system gains and losses and thefact that the Agua Dulce System used alternate interconnects before itsconnection during 2002 to the Webb/Duval Gathering System. The Webb/DuvalGathering System has an estimated current capacity of 219,000 Mcf/d.

**Coastal Waters Region**

The Coastal Waters Region is comprised of two pipelinesystems, the Copano Bay System and the Encinal Channel Pipeline, consisting ofapproximately 142 miles of pipelines operating both onshore and offshore inAransas, Nueces, Refugio and San Patricio Counties, Texas. This region ismanaged from our field office in Lamar, Texas.

*CopanoBay System.**  *The Copano Bay System currently comprisesapproximately 119 miles of natural gas pipelines, which range in size fromthree inches to 12 inches in diameter. Currently, the Copano Bay System gathersnatural gas from the offshore Matagorda Island Block 721 area, Aransas andCopano Bays, and adjacent onshore lands through Aransas Bay and onshore atRockport, Texas. Natural gas and condensate are separated at our Lamarseparation and dehydration facility, and the natural gas is delivered toEnterprise Products Partners, L.P./Channel at Lamar, Texas. The condensate isstored and redelivered to producers and shippers who then truck the product tomarket. The Copano Bay System gathers or transports substantially all of thenatural gas in the Copano Bay and Aransas Bay area. The Copano Bay System hasten active receipt meters, representing nine producers and one shipper.

Average throughput volume on this system was2,722 Mcf/d and 11,403 Mcf/d for the years ended December 31, 2005and 2004, respectively. The throughput capacity of this system is 37,000 Mcf/dand has 25,000 Mcf/d of dehydration capacity.

*Encinal Channel Pipeline.**  *The EncinalChannel Pipeline is an approximately 23-mile pipeline that is currentlyinactive. The Encinal Channel Pipeline measures three inches to 12 inches indiameter and is located in Nueces and San Patricio Counties, Texas. The EncinalChannel Pipeline currently has an estimated throughput capacity of 145,000Mcf/d. There is no installed compression or dehydration on this pipeline. Webelieve inland bay lease sales will ultimately provide natural gas purchase andtransportation opportunities for this pipeline.

**Central Gulf CoastRegion**

The Central Gulf Coast Region is composed of twointrastate natural gas gathering systems totaling approximately 231 miles andoperating in Colorado, Dewitt, Lavaca and Wharton Counties, Texas. This regionis operated from our Houston Central Processing Plant located approximately 100miles southwest of Houston. Interconnects at the tailgate of our HoustonCentral Processing Plant include KMTP, Tennessee Gas Pipeline, Texas EasternTransmission and Houston Pipe Line Company.

*SheridanSystem.**  *The Sheridan System consists ofapproximately 60 miles of natural gas gathering lines ranging in size from fourinches to 10 inches in diameter, and gathers natural gas from 23 active receiptmeters and one third-party pipeline interconnect located in Colorado and LavacaCounties, Texas, representing 15 producers and three shippers. There is noinstalled compression or dehydration on this system. Natural gas from theSheridan System is gathered and transported to our Houston Central ProcessingPlant for treatment of carbon dioxide, processing and ultimate delivery intothe interconnects at the tailgate of our processing plant. The Sheridan Systemalso has a pipeline interconnect with the Enterprise Products’ ChestervilleSystem.

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Average throughput volume on this system was26,042 Mcf/d and 18,338 Mcf/d for the years ended December 31, 2005and 2004, respectively. The Sheridan System has an estimated capacity of 45,000Mcf/d.

*ProvidentCity System.**  *Thissystem consists of approximately 171 miles of natural gas gathering linesranging in size from three inches to 14 inches in diameter, and gathersnatural gas from 74 receipt points and one third-party pipeline interconnectlocated in Colorado, DeWitt, Lavaca and Wharton Counties, Texas, representing46 producers and seven shippers. There is no compression or dehydrationinstalled on this system. The Provident City System has a pipeline interconnectwith Duke Energy Field Services’ San Jacinto Pipeline System.

Average throughput volumeon this system was 66,830 Mcf/d and 56,137 Mcf/d for the years ended December 31,2005 and 2004, respectively. The Provident City System has an estimatedcapacity of 160,000 Mcf/d.

**Upper Gulf CoastRegion**

Our Upper Gulf Coast Region is composed of threepipeline systems consisting of approximately 230 miles of pipeline used forgathering, transportation and sales of natural gas in Houston, Walker, Grimes,Montgomery and Harris Counties, Texas. This region is managed from our fieldoffice in Conroe, Texas.

*SamHouston System.**  *The Sam Houston System includesapproximately 125 miles of natural gas pipeline that gathers natural gas andreceives natural gas from other pipelines for ultimate delivery to markets onthe system. This gathering and transportation pipeline ranges in size from fourinches to 12 inches in diameter. We currently gather natural gas from 18 activereceipt meters and five third-party pipeline interconnects, representing 10producers and three shippers.

The Sam Houston System has interconnects with HoustonPipe Line Company, Lone Star Pipeline Company, KMTP, Vantex Gas PipelineCompany and Texas Eastern Transmission. The Sam Houston System delivers naturalgas to multiple CenterPoint Energy city gates in The Woodlands, Conroe andHuntsville, Texas, to Universal Natural Gas, a gas company providing servicesto residential markets in southern Montgomery County, Texas and to Entergy’sLewis Creek Generating Plant and several industrial consumers. There is nocompression or dehydration installed on this pipeline system.

Average net throughput volume on this system was 35,744 Mcf/d and 33,489 Mcf/d for theyears ended December 31, 2005 and 2004, respectively. The Sam HoustonSystem has an estimated capacity of approximately 119,000 Mcf/d.

*GrimesCounty System.**  *The Grimes County System is anapproximately 77-mile natural gas gathering system located in GrimesCounty, Texas, which consists of natural gas pipelines ranging in size from twoinches to 12 inches in diameter. We currently gather natural gas from 13 activereceipt meters representing six producers, and deliver all of the natural gasto our Sam Houston System. There is 311 horsepower of compression and no activedehydration on this pipeline system.

Average throughput volume on this system was2,402 Mcf/d and 2,514 Mcf/d for the years ended December 31, 2005 and2004, respectively. The Grimes County System has an estimated capacity of23,000 Mcf/d.

*LakeCreek Pipeline.**  *TheLake Creek Pipeline is an approximately 28-mile natural gas pipelinesystem located in Harris and Montgomery Counties, Texas. The Lake CreekPipeline is comprised of 6-inch and 8-inch diameter natural gaspipelines. This pipeline has three receipt points and a bi-directional receiptand delivery point with Houston Pipe Line Company near the Bammel Storage fieldin Harris County. The majority of the natural gas transported on this pipelineis delivered to CenterPoint Energy at delivery points serving the westernportion of The Woodlands, Texas and the surrounding area. Natural gas is also deliveredto Universal Natural Gas.

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Average throughput volumeon this system was 539 Mcf/d and 4,216 Mcf/d for the years ended December 31,2005 and 2004, respectively. The Lake Creek Pipeline has an estimated capacityof 20,000 Mcf/d.

**Texas Gulf Coast Processing Segment**

The Texas Gulf Coast Processing segment includes ourHouston Central Processing Plant located near Sheridan, Texas in ColoradoCounty and our Sheridan NGL Pipeline that runs from the tailgate of theprocessing plant to the Houston area.

*HoustonCentral Processing Plant.**  *Our Houston Central Processing Plantis the third largest in the state of Texas in terms of throughput capacity andthe second largest and the most fuel efficient processing plant in the areas inwhich we operate. Our Houston Central Processing Plant removes NGLs from thenatural gas supplied by the KMTP Laredo-to-Katy pipeline, which it straddles,and the pipelines in our Central Gulf Coast Region gathering systems and, tothe extent commercially desirable, fractionates the NGLs into separatemarketable products for sale to third parties. The Houston Central ProcessingPlant was originally constructed in 1965 by Shell and was comprised of a singlerefrigerated lean oil train and a fractionation facility. The plant wasmodified by Shell in 1985 with the addition of a second refrigerated lean oiltrain and in 1986 with the addition of a cryogenic turbo-expander train. This700 MMcf/d gas processing plant includes 6,689 horsepower of inlet compression,8,400 horsepower of tailgate compression, a 700 gallon per minute aminetreating system for removal of carbon dioxide and low-level hydrogen sulfide,two 250 MMcf/d refrigerated lean oil trains, one 200 MMcf/d cryogenicturbo-expander train, a 25,000 Bbls/d NGL fractionation facility, and 882,000gallons of storage capacity for propane, butane and natural gasoline mix andstabilized condensate. The plant also has multiple tailgate interconnects forredelivery of natural gas with KMTP, Houston Pipe Line Company, Tennessee GasPipeline Company and Texas Eastern Transmission. In addition, at the tailgateof the plant, we operate our Sheridan NGL Pipeline for transporting NGLs andTEPPCO operates an 8-inch diameter crude oil and stabilized condensatepipeline that runs to refineries in the greater Houston area. In addition, wehave an interconnect to a 6-inch diameter pipeline for transportation ofethane and propane operated by a subsidiary of Dow Chemical to Dow’s Freeportfacility. Our Houston Central Processing Plant and related facilities arelocated on a 163-acre tract of land, which we lease under three long-termlease agreements.

In 2003, wemodified the processing plant to provide natural gas conditioning capability byinstalling two new 700 horsepower, electric-driven compressors to providepropane refrigeration through the lean oil portion of the plant, which enablesus to shut down one of our steam-driven turbines when we are conditioningnatural gas. These modifications provide us with the capability to process gasonly to the extent required to meet pipeline hydrocarbon dew pointspecifications. Our ability to condition gas, rather than fully process it,provides us with significant benefits during periods when processing is noteconomic (when the price of natural gas is high compared to the price of NGLs),including:

·       providingus with the ability to minimize the level of NGLs removed from the natural gasstream during periods when prices are high relative to NGL prices; and

·       allowingus to operate our Houston Central Processing Plant more efficiently at a muchreduced fuel consumption rate while still meeting downstream pipelinehydrocarbon dew point specifications.

As a result, during these periods the combination ofreduced NGL removal and reduced fuel consumption at our plant allows us topreserve a greater portion of the value of the natural gas.

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Our Houston Central Processing Plant has an inletcapacity of approximately 700 MMcf/d and had an average throughput of 530 MMcf/dfor the year ended December 31, 2005 compared with an average dailythroughput of 529 MMcf/d for the year ended December 31, 2004. The averagedaily volume of ethane and propane delivered from the plant to the Dow NGLpipeline was 8,697 Bbls/d and 10,667 Bbls/d for the years ended December 31,2005 and 2004, respectively. The average daily volume of butane and naturalgasoline mix delivered to the Sheridan NGL pipeline was 3,552 Bbls/d and4,322 Bbls/d for the years ended December 31, 2005 and 2004, respectively.The average daily volume of stabilized condensate delivered from the plant tothe TEPPCO crude oil pipeline was 808 Bbls/d and 379 Bbls/d for theyears ended December 31, 2005 and 2004, respectively.

*SheridanNGL Pipeline.**  *Our 104-mile, 6-inch diameterSheridan NGL pipeline originates at the tailgate of our Houston CentralProcessing Plant and currently delivers NGLs into the Enterprise ProductsPartners’ Seminole Pipeline for ultimate redelivery for further transportation andfractionation.

Average throughput volumeon this system was 3,552 Bbls/d and 4,322 Bbls/d for the years ended December 31,2005 and 2004, respectively. The line has a current capacity of 20,840 Bbls/dof NGLs, which we believe could be increased with the installation ofadditional pump facilities.

**Competition in OurTexas Gulf Coast Operating Region**

The natural gas gathering, transmission, treating,processing and marketing industries are highly competitive. We face strongcompetition in acquiring new natural gas supplies. Many of our competitors inthe Texas Gulf Coast region have capital resources and control supplies ofnatural gas greater than ours. Our competitors include major interstate andintrastate pipelines, and other natural gas gatherers that gather, process andmarket natural gas. Our major competitors for natural gas supplies and marketsin our four Texas operating regions include Enterprise Products Partners, L.P.,Lobo Pipeline Company (an affiliate of ConocoPhillips), KMTP, Duke Energy FieldServices, Crosstex Energy, and Houston Pipe Line Company. Our primarycompetitors for our Texas Gulf Coast Processing segment are Enterprise,ExxonMobil and Duke Energy Field Services. Competition for natural gas suppliesis primarily based on the reputation, efficiency, flexibility and reliabilityof the gatherer, the pricing arrangements offered by the gatherer, the locationof the gatherer’s pipeline facilities and the ability of the gatherer to offera full range of services, including processing, conditioning and treatingservices. We provide comprehensive services to natural gas producers, includingnatural gas gathering, transportation, compression, dehydration, treating,conditioning and processing. We believe our ability to furnish these servicesgives us an advantage in competing for new supplies of natural gas because wecan provide the services that producers, marketers and others require toconnect their natural gas quickly and efficiently. In addition, usingcentralized treating and processing facilities, we can in most cases attachproducers that require these services more quickly and at a lower initialcapital cost due in part to the elimination of some field equipment and greatereconomies of scale at our Houston Central Processing Plant. For natural gasthat exceeds the maximum carbon dioxide and NGL specifications forinterconnecting pipelines and downstream markets, we believe that we offertreating, conditioning and other processing services on competitive terms. Inaddition, with respect to natural gas customers attached to our pipelinesystems, we are able to vary quantities of natural gas delivered to customersin response to market demands.

The primary differencebetween us and some of our competitors is that we provide an integrated andresponsive package of midstream services, while some of our competitors provideonly certain services. We believe that offering an integrated package ofservices, while remaining flexible in the types of contractual arrangementsthat we offer producers, allows us to compete more effectively for new naturalgas supplies.

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**Texas Gulf CoastNatural Gas Supply**

Our Texas assets are located in areas that haveexperienced significant levels of drilling activity, providing us withopportunities to access newly developed natural gas supplies. We generally donot obtain independent evaluations of reserves dedicated to our pipelinesystems due to the cost of such evaluations and the lack of publicly availableproducer reserve information. Accordingly, we do not have estimates of totalreserves dedicated to our Texas systems or the anticipated life of suchproducing reserves.

During the year ended December 31, 2005, our topproducers by volume of natural gas were Dominion OK TX Exploration, MesteñaOperating, Noble Energy, Westport Oil and Gas Company (a subsidiary ofKerr-McGee), Edge Petroleum and El Paso Production Company,****which collectively accounted forapproximately 46% of the natural gas delivered to our Texas Gulf Coast naturalgas gathering and intrastate pipeline systems during that period.

We contract for supplies of natural gas from producersprimarily under two types of arrangements, natural gas purchase contracts andfee-for-service contracts. The primary term of each contract variessignificantly, ranging from one month to the life of the dedicated production. Thespecific terms of each natural gas supply contract are based upon a variety offactors including gas quality, pressure of natural gas production relative todownstream transporter pressure requirements, the competitive environment atthe time the contract is executed and customer requirements. For a detaileddiscussion of our contracts, please read “Management’s Discussion and Analysisof Financial Condition and Results of Operation—Our Contracts—Texas Gulf CoastPipelines Contracts.”

We continually seek newsupplies of natural gas, both to offset natural declines in production fromconnected wells and to increase throughput volume. We obtain new natural gassupplies in our operating areas by contracting for production from new wells,connecting new wells drilled on dedicated acreage or by obtaining natural gasthat was previously transported on other gathering systems.

**Kinder Morgan TexasPipeline**

KMTP is an intrastate natural gas pipeline system thatis principally located in the Texas Gulf Coast region. KMTP transports naturalgas from producing fields in South Texas, the Texas Gulf Coast and the Gulf ofMexico to markets in southeastern Texas. KMTP acts as a seller of natural gasas well as a transporter. We utilize KMTP as a transporter because our HoustonCentral Processing Plant straddles its 30-inch diameter KMTPLaredo-to-Katy pipeline. By using KMTP as a transporter, we can transportnatural gas from many of our pipeline systems to our processing plant anddownstream markets. Under our contractual arrangement related to KMTP Gas, wereceive natural gas at our plant, process or condition the natural gas and sellthe NGLs to third parties at market prices. We refer to the natural gas deliveredinto the KMTP Laredo-to-Katy pipeline from sources other than our gatheringsystems as “KMTP Gas.”  Because theextraction of NGLs from the natural gas stream during processing orconditioning reduces the Btus of the natural gas, our arrangement with KMTPrequires us to purchase natural gas at market prices to replace the loss inBtus. Pursuant to an amendment to this contract with KMTP, effective January 1,2004, we pay a fee to KMTP based on the NGL content of the KMTP Gas only duringperiods of favorable processing margins. In addition, the amendment providesthat during periods of unfavorable processing margins, KMTP pays us a fixed feeplus an additional payment based on the index price of natural gas. Ourcontract arrangement relating to KMTP Gas expires on August 31, 2006, withautomatic annual renewals thereafter unless canceled by either party upon 180days’ prior notice. We are currently in the process of discussing mutuallybeneficial revisions and an extension to our contract with KMTP.

For the year ended December 31,2005, approximately 83% of the natural gas volumes processed or conditioned atour Houston Central Processing Plant was delivered to the plant through theKMTP Laredo-to-Katy pipeline while the remaining 17% was delivered directlyinto the plant from our gathering 

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systems.Of the natural gas delivered into the plant from the KMTP Laredo-to-Katypipeline, approximately 27% was delivered from gathering systems controlled byus and 73% was delivered into KMTP’s pipeline from other sources. Of the totalvolume of NGLs extracted at the plant during this period, 39% was attributableto KMTP Gas, while 61% was attributable to gas from gathering systemscontrolled by us, including our gathering systems connected directly to theplant.

**Mid-Continent Operations Segment**

On August 1, 2005, we completed the ScissorTailAcquisition. We refer to the business and properties of ScissorTail as ourMid-Continent Operations segment.

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The following maprepresents our Mid-Continent Operations segment:

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Wehave set forth in the table below summary information describing ourMid-Continent Operations gathering systems and processing assets:

| ** **              | ** ** | ** **     | ** ** | ** **                        | ** ** | ** **          | ** ** | **Average**                                    | ** ** | **Year Ended  December 31, 2005**                           | ** ** |
|-------------------------|------------|----------------|------------|-----------------------------------|------------|---------------------|------------|------------------------------------------------|------------|----------------------------------------------------------------------------|------------|
| **Asset**               | ** ** | ** **     | ** ** | **Initial  Acquisition  Date(1)** | ** ** | **Length  (miles)** | ** ** | **Existing  Throughput  Capacity  (Mcf/d)(2)** | ** ** | **Throughput  Volumes at Time  of Acquisition  (Mcf/d)(3)** | ** ** | **Average  Throughput  Volumes  (Mcf/d)** | ** ** | **Utilization  of  Capacity** | ** ** |
| **Gathering Pipelines** |       |           |       |                              |       |                |       |                                           |       |                                                                       |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Stroud System           |       | July 2000 |       |                              | 709        |                |       |                                           | 102,000    |                                                                       |       |   | 42,485 |   |   |   | 64,710 |   |   |   | 63 | % |   |
| Osage System            |       | June 2003 |       |                              | 549        |                |       |                                           | 17,000     |                                                                       |       |   | 11,826 |   |   |   | 14,800 |   |   |   | 87 | % |   |
| Milfay System           |       | June 2003 |       |                              | 369        |                |       |                                           | 15,000     |                                                                       |       |   | 9,460 |   |   |   | 12,112 |   |   |   | 81 | % |   |
| Glenpool System         |       | June 2003 |       |                              | 1,014      |                |       |                                           | 23,500     |                                                                       |       |   | 10,538 |   |   |   | 9,671 |   |   |   | 41 | % |   |
| Twin Rivers System      |       | June 2003 |       |                              | 526        |                |       |                                           | 16,000     |                                                                       |       |   | 12,555 |   |   |   | 11,107 |   |   |   | 69 | % |   |
| Mountain System(4)      |       | June 2003 |       |                              | 164        |                |       |                                           | 45,000     |                                                                       |       |   | 22,652 |   |   |   | 19,611 |   |   |   | 44 | % |   |
| Total                   |       |           |       |                              | 3,331      |                |       |                                           | 218,500    |                                                                       |       |   | 109,516 |   |   |   | 132,011 |   |   |   |   |   |   |
|                         |            |                |            |                                   |            |                     |            |                                                |            |                                                                            |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

| ** **            | ** ** | ** **     | ** ** | ** **                        | ** ** | **Average**                                    | ** ** | **Year Ended  December 31, 2005**                      | ** ** |
|-----------------------|------------|----------------|------------|-----------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------------------------------|------------|
| **Asset**             | ** ** | ** **     | ** ** | **Initial  Acquisition  Date(1)** | ** ** | **Existing  Throughput  Capacity  (Mcf/d)(2)** | ** ** | **Inlet  Volumes at Time  of Acquisition  (Mcf/d)(3)** | ** ** | **Average  Inlet  Volumes  (Mcf/d)** | ** ** | **Utilization  of  Capacity** | ** ** |
| **Processing Plants** |       |           |       |                              |       |                                           |       |                                                                  |       |   |   |   |   |   |   |   |   |   |   |
| Paden                 |       | June 2001 | (5)        |                              | 60,000     |                                           |       |                                                                  | —     |   |   |   | 35,009 |   |   |   | 58 | % |   |
| Milfay                |       | June 2003 |       |                              | 15,000     |                                           |       |                                                                  | 8,661      |   |   |   | 10,891 |   |   |   | 73 | % |   |
| Glenpool              |       | June 2003 |       |                              | 25,000     |                                           |       |                                                                  | 9,941      |   |   |   | 9,083 |   |   |   | 36 | % |   |
| Total                 |       |           |       |                              | 100,000    |                                           |       |                                                                  | 18,602     |   |   |   | 54,983 |   |   |   |   |   |   |
|                       |            |                |            |                                   |            |                                                |            |                                                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          The initial acquisitiondate is the date that ScissorTail first commenced operations with respect toany system or facility.

(2)          Many capacity values arebased on current operating configurations and could be increased throughadditional compression, increased delivery meter capacity and/or other facilityupgrades including, for example, larger dehydration capacity.

(3)          Reflects averagethroughput for the first month in which ScissorTail operated the assets.

(4)          The Mountain Systemconsists of three systems: Blue Mountain, Cyclone Mountain and Pine Mountain.

(5)          Reflects date ofconstruction or acquisition by ScissorTail.

Our Mid-ContinentOperations pipeline gathering systems include: Stroud, Osage, Milfay, Glenpool,Twin Rivers, Blue Mountain, Cyclone Mountain and Pine Mountain. The PadenPlant, Glenpool Plant and Milfay Plant are integrated within the Stroud System,Glenpool System and Milfay System, respectively.

***Stroud System***

The Stroud gathering system is comprised ofapproximately 709 miles of pipeline ranging from two inches to 12 inches indiameter. The Stroud system is located in Payne, Lincoln, Oklahoma,Pottawatomie, Seminole, and Okfuskee counties, Oklahoma. Average throughput forthe period from August 1, 2005 through December 31, 2005 was64,710 Mcf/d. Approximately 26,638 Mcf/d of these volumes wasdelivered to Enogex’s Harrah Plant and the remainder, approximately38,072 Mcf/d, was delivered to our Paden 

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Plant. As of December 31,2005, there were approximately 440 active receipt meters connected to theStroud gathering system.

The natural gas supplied to the Stroud system isgenerally under acreage dedication and long-term agreements with remainingterms ranging from two to fifteen years. New Dominion, the largest producer forour Mid-Continent Operations segment, recently executed a 10-yearextension of its dedication to us. Under this agreement, existing and futuredevelopments on 1.1 million acres in the Stroud system are dedicated to us tothe year 2020. We also have dedications from two additional producers coveringproduction from an aggregate of over 250,000 acres pursuant to contracts endingbetween 2009 and 2011.

For the period from August 1,2005 through December 31, 2005, approximately 59% of the net averagethroughput volumes from the Stroud System were processed at our Paden Plant. ThePaden Plant is a turbo-expander cryogenic facility with current natural gasthroughput capacity of approximately 60,000 Mcf/d. Placed into service in June 2001,the plant has the ability to reduce the ethane extracted from natural gasprocessed, or “reject ethane”. The ability to either retain ethane or reject itprovides us with an advantage as ethane may be more valuable in liquid form(after extraction from natural gas) or retained within the gas stream, dependingon market prices. During the period from August 1, 2005 through December 31,2005, average inlet volumes were 35,009 Mcf/d and approximately4,089 Bbls/d of raw mix NGLs were produced, together with approximately30,104 MMBtu/d of residue gas and 518 Bbls/d of condensate. Fieldcompression provides the necessary pressure at the inlet, so inlet compressionis not required. The Paden Plant has an amine sweetening process unit forremoval of hydrogen sulfide and carbon dioxide but this unit has not beenutilized to date due to current upstream treatment by producers. The plant alsohas inlet condensate facilities including vapor recovery and a condensatestabilizer. The residue natural gas from the Paden Plant is delivered intoEnogex’s natural gas transmission system for redelivery to NGPL-Texok andCenterPoint-East Zone and the NGLs are delivered to Oneok Hydrocarbon, L.P. Dueto increasing production volumes around the Paden Plant, the plant is expectedto be operating at near full capacity by the end of 2006. The remainingthroughput volumes from the Stroud System are processed at Enogex’s HarrahPlant under an agreement with Enogex. For the period from August 1, 2005through December 31, 2005, our average daily inlet volumes processed atthe Enogex Harrah Plant were 16,009 Mcf/d and approximately2,148 Bbls/d of raw mix NGLs were produced, together with approximately12,192 MMBtu/d of residue gas and 401 Bbls/d of condensate.

***Osage System***

The Osage gathering system is comprised ofapproximately 549 miles of pipeline ranging from two inches to eight inches indiameter. The Osage System is located in Osage, Pawnee, Payne, Washington andTulsa counties, Oklahoma. Average throughput for the period from August 1,2005 through December 31, 2005 was 14,800 Mcf/d. As of December 31,2005, there were approximately 166 active receipt meters connected to the Osagegathering system. Given the lean nature of the wellhead production, themajority of the natural gas gathered on the Osage System is not processed. Downstreampipeline interconnects include Enogex, Oneok Gas Transmission and Keystone Gas.Gas that is delivered to Keystone Gas is processed by Duke Energy FieldServices at their Kingfisher Plant and we receive a share of natural gasliquids and residue gas. For the period from August 1, 2005 through December 31,2005, our average daily inlet volumes processed at the Duke Kingfisher Plantwere 751 Mcf/d and approximately 81 Bbls/d of raw mix NGLs wereproduced, together with approximately 505 MMBtu/d of residue gas and4 Bbls/d of condensate.

The primary producingareas that supply the Osage System are located in the southern part of thesystem. The area served by the Osage System is mature and current drillingactivity is focused on the development of coalbed methane gas produced in theRowe formation.

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***Milfay System***

The Milfay gathering system is comprised ofapproximately 369 miles of pipeline ranging from two inches to eight inches indiameter. The Milfay System is located in Tulsa, Creek, Payne, Lincoln, andOkfuskee counties, Oklahoma. Average throughput for the period fromAugust 1, 2005 through December 31, 2005 was 12,112 Mcf/d. As ofDecember 31, 2005, there were approximately 246 active receipt metersconnected to the Milfay gathering system.

We believe that there will be continued volume growth inthe Milfay system as a result of continued development of the Bartlesville,Hunton and Dutcher formations. This growth is consistent with significantvolume increases from 2004 to 2005 due to wells drilled and successfullycompleted in the Bartlesville formation.

Substantially all of the gas from the Milfay gatheringsystem is delivered to the Milfay processing plant, which consists of a propanerefrigeration facility with natural gas throughput capacity of approximately15,000 Mcf/d. Average inlet volumes for the period from August 1, 2005through December 31, 2005 were 10,891 Mcf/d and approximately829 Bbls/d of raw mix NGL was produced, along with about9,321 MMBtu/d of residue gas. Residue natural gas is delivered into the OneokGas Transmission system and the NGLs are delivered to Oneok Hydrocarbon, L.P.

***Glenpool System***

The Glenpool gathering system is comprised ofapproximately 1,014 miles of pipeline ranging from two inches to 10 inches indiameter. The Glenpool System is located in Tulsa, Wagoner, Muskogee, McIntosh,Okfuskee, Okmulgee and Creek counties, Oklahoma. Average throughput for theperiod from August 1, 2005 through December 31, 2005 was 9,671 Mcf/d.As of December 31, 2005, there were approximately 408 active receiptmeters connected to the Glenpool System.

Substantially all of thegas from the Glenpool gathering system is delivered to the Glenpool processingplant, which consists of a cryogenic facility with natural gas throughputcapacity of approximately 25,000 Mcf/d. Average inlet volumes for the periodfrom August 1, 2005 through December 31, 2005 were 9,083 Mcf/dand approximately 582 Bbls/d of raw mix NGLs were produced, along withabout 8,536 MMBtu/d of residue natural gas. Residue natural gas isdelivered into either OGT or the American Electric Power Riverside Power Plantand the NGLs are delivered to Oneok Hydrocarbon, L.P.

***Twin Rivers System***

The Twin Rivers gatheringsystem is comprised of approximately 526 miles of pipeline ranging from twoinches to 12 inches in diameter. The Twin Rivers System is located in Okfuskee,Seminole, Hughes, Pontotoc and Coal counties, Oklahoma. Average throughput forthe period from August 1, 2005 through December 31, 2005 was11,107 Mcf/d. As of December 31, 2005, there were approximately 317active receipt meters connected to the system and substantially all of thesystem’s volumes are delivered to Enogex’s Wetumka Processing Plant. Theresidue natural gas is delivered into Enogex’s natural gas transmission systemfor redelivery to CenterPoint-East Zone and the NGLs are sold to Enogex. Forthe period from August 1, 2005 through December 31, 2005, our averagedaily inlet volumes processed at the Enogex Wetumka Plant were 8,103 Mcf/dand approximately 753 Bbls/d of raw mix NGLs were produced, together withapproximately 6,898 MMBtu/d of residue gas and 18 Bbls/d ofcondensate.

***Mountain Systems***

Our three Mountain Systemsare located in the Arkoma Basin and include Blue Mountain, Cyclone Mountain andPine Mountain systems. These systems comprise a total of approximately 164miles of pipeline ranging from two inches to 20 inches in diameter. Thesesystems are located in Atoka, Pittsburg and Latimer counties, Oklahoma. Averagethroughput for the period from August 1, 2005 through 

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December 31,2005 was 19,611 Mcf/d. As of December 31, 2005, there wereapproximately 137 active receipt meters connected to the Mountain gatheringsystems. Due to the lean nature of the wellhead production, natural gasgathered on our Mountain Systems does not require processing. Downstreampipeline interconnects include Blue Mountain, CenterPoint—East Zone, CycloneMountain—Enogex, NGPL-Texok, CenterPoint—East Zone and Pine Mountain—CenterPoint—EastZone.

***Southern Dome, LLC***

As part of the ScissorTail Acquisition, we acquired amajority interest in Southern Dome, LLC, or Southern Dome, formed for thepurpose of providing gathering and processing services within the Southern Domeprospect in the southern portion of Oklahoma County and became its operator.Southern Dome is constructing a processing plant and residue pipelines tosupport anticipated future production in the Southern Dome area. Southern Domehas signed a 20-year gas purchase and processing agreement with theleading producer for our Mid-Continent Operations, New Dominion. Southern Domehas secured a 40-acre site for the plant, and is in the process ofobtaining right-of-way permits. Construction of the plant, building, residuepipelines and compression are in progress. Our expected share of theconstruction cost of the project is anticipated to be $18.0 million. Theprocessing plant and pipelines are expected to begin service during April 2006.In addition, Southern Dome will operate New Dominion’s gathering lines whichare inlet to the plant for a fee.

We are required to make100% of the capital contributions required by Southern Dome until such time asour capital account balance equals 73% of the aggregate capital accountbalances of us and the other members. The maximum amount of capitalcontributions that we are obligated to make to Southern Dome is $18.3 million.Additionally, prior to achievement of “payout,” we are entitled to receive69.5% of member distributions and after achievement of “payout,” to 50.1% ofmember distributions. Payout is achieved once we have received distributionsequal to its capital contributions plus a stated rate of return. We are themanaging member of Southern Dome.

**Mid-ContinentOperations Natural Gas Supply**

We have pipelines and related assets in 21 counties inOklahoma that have experienced increased levels of drilling activity from 2003to 2005, which has led to increased volumes of natural gas through ourMid-Continent Operations pipeline systems. Based on discussions between us andproducers in this area about their production plans, we expect to increase thevolumes connected to these systems, providing us with opportunities to accessnewly developed natural gas supplies. We have not historically obtainedindependent evaluations of reserves dedicated to our pipeline systems due tothe cost of such evaluations and the lack of publicly available producerreserve information. Accordingly, we do not have precise estimates of totalreserves dedicated to our Mid-Continent systems or the anticipated life of suchproducing reserves.

During the period from August 1, 2005 through December 31,2005, our Mid-Continent Operations’ top producers by volume of natural gas wereNew Dominion, Altex Resources, Amvest, Chesapeake, and Special Energy, whichcollectively accounted for approximately 56%****ofthe natural gas delivered to our Mid-Continent Operations natural gas gatheringand intrastate pipeline systems.

Our Mid-Continent Operations segment had 1,658 activereceipt meters as of December 31, 2004 and added 56 receipt meters throughDecember 31, 2005, more than offsetting the natural production decline ofexisting wells currently connected to its systems. Average wellhead productionincreased from 112,372 Mcf/d in 2004 compared with 132,011 Mcf/d in 2005,an increase of approximately 18%. The greatest growth came from the Paden Plantarea of the Stroud system, where, on average, production increased from28,376 Mcf/d for 2004 as compared with 38,072 Mcf/d for 2005. TheStroud system is a current primary focus for expansion. The Hunton formationunderlies virtually the entire Stroud system and is the 

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primary reservoir beingexploited across that system. Producers are utilizing horizontal well bores anddewatering techniques to economically access the gas entrained in thedolomite/limestone reservoir. As these drilling techniques applied to thisformation have improved, the pace of drilling has increased significantly, with52 wells drilled in the Stroud system in 2004 and 50 wells drilled during theyear ended December 31, 2005.

We continually seek newsupplies of natural gas, both to offset natural declines in production fromconnected wells and to increase throughput volume. We obtain new natural gassupplies in our operating areas by contracting for production from new wells,connecting new wells drilled on dedicated acreage or by obtaining natural gassupplies that were previously transported on other third party gatheringsystems. Our leading producer by volume has dedicated all of its existing andfuture production from property it leases within a 1.1 million acre area to uspursuant to a contract that extends until 2020. We also have dedications fromtwo additional producers covering existing and future production from aproperty leased by the producers within an aggregate of over 250,000 acrespursuant to contracts ending between 2009 and 2011.

**Competition in OurMid-Continent Operating Region**

Competition for natural gas supplies in ourMid-Continent Operations’ region is primarily based on the reputation,efficiency, flexibility and reliability of the gatherer, the pricingarrangements offered by the gatherer, the location of the gatherer’s pipelinefacilities and the ability of the gatherer to offer a full range of services,including natural gas gathering, transportation, compression, dehydration andprocessing.

We believe the primary difference between us and someof our competitors is that we provide an integrated and responsive package ofmidstream services, while some of our competitors provide only certain services.We believe that offering an integrated package of services, while remainingflexible in the types of contractual arrangements that we offer producers,allows us to compete more effectively for new natural gas supplies in ourregions of operations.

Prior to the ScissorTail Acquisition, it also made asignificant investment in installing additional compression units, with manybeing new limited emissions multi-stage compressors. These compressors allowfor quicker permitting and installation and also help us more efficientlyprovide the necessary pressure (at the inlet), providing us with an advantageover competitors without these capabilities. Additionally, substantially all ofour systems offer low-pressure gathering service. The low pressure design ofour systems allows for future system expansion as new wells are drilled and/orexisting wells are re-completed.

Our major competitors fornatural gas supplies and markets in our Mid-Continent Operations’ regioninclude CenterPoint, Duke Energy Field Services, Enogex and Enerfin.

**Industry Overview**

The midstream natural gas industry is the link betweenthe exploration and production of natural gas and the delivery of itscomponents to end-use markets and consists of natural gas gathering,compression, dehydration, treating, conditioning, processing, fractionation andtransportation. The midstream industry is generally characterized by regionalcompetition based on the proximity of gathering systems and processing plantsto natural gas producing wells.

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We provide naturalgas gathering, treating, conditioning, processing, fractionation,transportation, dehydration and compression services to our customers. Theseprocesses are illustrated in the following diagram.

·       *Natural gas gathering and compression.  *Thenatural gas gathering process begins with the drilling of wells into gasbearing rock formations. Once a well has been completed, the well is connectedto a gathering system. Gathering systems generally consist of a network ofsmall diameter pipelines that collect natural gas from points near producingwells and transport it to larger pipelines for further transmission. Gatheringsystems are operated at design pressures that will maximize the totalthroughput from all connected wells.

·       *Compression.  *Lower pressuregathering systems allow wells, which produce at progressively lower fieldpressures as they age, to remain connected to the gathering system and continueto produce for longer periods of time. As the well pressure declines, itbecomes increasingly difficult to deliver the remaining production in theground against a higher pressure that exists in the connecting gathering system.Natural gas compression is a mechanical process in which a volume of gas at anexisting pressure is compressed to a desired higher pressure. Compressionallows gas that no longer naturally flows into a higher-pressure downstreampipeline to be brought to market. Field compression is typically used to allowa gathering system to operate at a lower pressure or provide sufficientdischarge pressure to deliver gas into a higher-pressure downstream pipeline. Iffield compression is not installed, then the remaining natural gas in theground will not be produced because it cannot overcome the higher gatheringsystem pressure. In contrast, if field compression is installed, then a wellcan continue delivering natural gas that otherwise would not be produced.

·       *Natural gas dehydration.  *Producednatural gas is saturated with water, which must be removed because thecombination of natural gas and water can form ice that can plug many differentparts of the pipeline gathering and transportation system and processing plants.Water in a natural gas stream can also cause corrosion when combined withcarbon dioxide or hydrogen sulfide in natural gas and condensed water in thepipeline can raise inlet pipeline pressure and cause a greater pressure dropdownstream. To avoid these potential issues and to meet downstream pipeline andend-user gas quality standards, natural gas is dehydrated to remove thesaturated water.

·       *Natural gas treating and blending.  *Naturalgas has a varied composition depending on the field, the formation and thereservoir from which it is produced. Natural gas from certain formations can behigh in carbon dioxide or hydrogen sulfide. Natural gas with high carbondioxide or hydrogen sulfide levels may cause significant damage to pipelinesand is generally not acceptable to end-users. To alleviate the potentialadverse effects of these contaminants, many pipelines regularly inject 

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corrosion inhibitors intothe gas stream. Additionally, to render natural gas with high carbon dioxide orhydrogen sulfide levels marketable, pipelines may blend the gas with gas thatcontains low carbon dioxide or hydrogen sulfide levels, or arrange fortreatment to remove carbon dioxide and hydrogen sulfide to levels that meetpipeline quality standards.

·       *Amine treating.  *The amine treatingprocess involves a continuous circulation of a liquid chemical called aminethat physically contacts with the natural gas. Amine has a chemical affinityfor hydrogen sulfide and carbon dioxide that allows it to absorb the impuritiesfrom the gas. After mixing, gas and amine are separated and the impurities areremoved from the amine by heating. The treating plants are sized by the aminecirculation capacity in terms of gallons per minute.

·       *Natural gas processing.  *Theprincipal components of natural gas are methane and ethane, but most naturalgas also contains varying amounts of other NGLs. Most natural gas produced by awell is not suitable for long-haul pipeline transportation or commercial useand must be processed to remove the heavier hydrocarbon components. Natural gasis processed not only to remove unwanted NGLs that would interfere withpipeline transportation or use of the natural gas, but also to separate fromthe gas those hydrocarbon liquids that have higher value as NGLs. The removaland separation of individual hydrocarbons by processing is possible because ofdifferences in weight, boiling point, vapor pressure and other physicalcharacteristics. Natural gas processing involves the separation of natural gasinto pipeline quality natural gas and a mixed NGL stream.

·       *Natural gas conditioning.  *Conditioningof natural gas is the process by which NGLs are removed from the natural gasstream by lowering the hydrocarbon dew point sufficiently to meet downstreamgas pipeline quality specifications. Although similar to natural gasprocessing, conditioning of natural gas removes only an absolute minimum amountof NGLs (typically the components of pentane and heavier products) from the gasstream. To lower the hydrocarbon dew point of a natural gas stream, thetemperature of the gas is reduced. Cryogenic processing consumes more fuelbecause it involves significantly lower temperatures than are required forconditioning of natural gas. Conditioning of natural gas, rather thanprocessing, is preferred during periods of unfavorable processing margins.

·       *NGL fractionation.  *Fractionation isthe process by which NGLs are further separated into individual, more valuablecomponents. NGL fractionation facilities separate mixed NGL streams intodiscrete NGL products: ethane, propane, isobutane, normal butane, naturalgasoline and stabilized condensate. Ethane is primarily used in thepetrochemical industry as feedstock for ethylene, one of the basic buildingblocks for a wide range of plastics and other chemical products. Propane isused both as a petrochemical feedstock in the production of ethylene andpropylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutaneis used principally to enhance the octane content of motor gasoline. Normalbutane is used as a petrochemical feedstock in the production of ethylene andbutadiene (a key ingredient in synthetic rubber), as a blend stock for motorgasoline and to derive isobutane through isomerization. Natural gasoline, amixture of pentanes and heavier hydrocarbons, is used primarily as motorgasoline blend stock or petrochemical feedstock. Stabilized condensate isprimarily used as a refinery feedstock for the production of motor gasoline andother products.

NGLsare fractionated by heating mixed NGL streams and passing them through a seriesof distillation towers. Fractionation takes advantage of the differing boilingpoints of the various NGL products. As the temperature of the NGL stream isincreased, the lightest (lowest boiling point) NGL product boils off the top ofthe tower where it is condensed and routed to storage. The mixture from thebottom of the first tower is then moved into the next tower where the processis repeated, and a different NGL product is separated and stored. This processis repeated until the 

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NGLshave been separated into their components. Because the fractionation processuses large quantities of heat, fuel costs are a major component of the totalcost of fractionation.

·       *Natural gas transportation.  *Naturalgas transportation pipelines receive natural gas from other mainlinetransportation pipelines and gathering systems and deliver the natural gas toindustrial end-users and utilities and to other pipelines.

·       *NGL transportation.  *NGLs are transported to market bymeans of pipelines, pressurized barges, rail car and tank trucks. The method oftransportation utilized depends on, among other things, the existing resourcesof the transporter, the locations of the production points and the deliverypoints, cost-efficiency and the quantity of NGLs being transported. Pipelinesare generally the most cost-efficient mode of transportation when large,consistent volumes of NGLs are to be delivered.

**Risk Management**

We are exposed to marketrisks, including changes in commodity prices and interest rates. We usefinancial instruments such as puts, swaps, and other derivatives to mitigatethe effects of the identified risks. In general, we attempt to hedge risksrelated to the variability of future earnings and cash flows resulting fromchanges in applicable commodity prices or interest rates so that we canmaintain cash flows sufficient to meet debt service, required capitalexpenditures, distribution objectives, and similar requirements. Our RiskManagement Policy prohibits the use of derivative instruments for speculativepurposes. For a more detailed discussion of our risk management activities,please read Item 7A “Quantitative and Qualitative Disclosures about MarketRisk.”

**Regulation**

*Regulation by the FERC ofInterstate Natural Gas Pipelines.**  *We do not own any interstatenatural gas pipelines, so the Federal Energy Regulatory Commission, or FERC,does not directly regulate any of our operations. However, FERC’s regulationinfluences certain aspects of our business and the market for our products. Ingeneral, FERC has authority over natural gas companies that provide natural gaspipeline transportation services in interstate commerce, and its authority toregulate those services includes:

·       thecertification and construction of new facilities;

·       theextension or abandonment of services and facilities;

·       themaintenance of accounts and records;

·       theacquisition and disposition of facilities;

·       theinitiation and discontinuation of services; and

·       variousother matters.

In recent years, the FERC has pursued pro-competitivepolicies in its regulation of interstate natural gas pipelines. However, wecannot assure you that the FERC will continue this approach as it considersmatters such as pipeline rates and rules and policies that may affectrights of access to natural gas transportation capacity. The distinctionbetween FERC-regulated transmission services and federally unregulatedgathering services has been the subject of regular litigation. As a result, theclassification and regulation of some of our gathering facilities andintrastate transportation pipelines may be subject to change based on futuredeterminations by FERC and the courts.

*IntrastatePipeline Regulation.**  *Ourintrastate natural gas pipeline operations generally are not subject to rateregulation by the FERC, but they are subject to regulation by the State ofTexas. Likewise, the intrastate natural gas pipeline facilities acquired in theScissorTail Acquisition are subject to regulation by the State of Oklahoma. However,to the extent that our intrastate pipelines transport natural gas in 

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interstate commerce, therates, terms and conditions of such transportation service are subject to theFERC jurisdiction under Section 311 of the Natural Gas Policy Act, whichregulates, among other things, the provision of transportation services by anintrastate natural gas pipeline on behalf of a local distribution company or aninterstate natural gas pipeline.

Some of our operations in Texas are subject to theTexas Gas Utility Regulatory Act, as implemented by the Railroad Commission ofTexas, or the TRRC. Generally the TRRC is vested with authority to ensure thatrates charged for natural gas sales or transportation services are just andreasonable. The rates we charge for transportation services are deemed just andreasonable under Texas law unless challenged in a complaint. We cannot predictwhether such a complaint will be filed against us or whether the TRRC willchange its regulation of these rates.

Some of the operations acquired under the ScissorTailAcquisition are subject to the Oklahoma Corporate Commission, or the OCCregulation as public utilities. Generally, the OCC is vested with authority toensure that rates charged for natural gas sales or transportation services arejust and reasonable. The rates charged by these assets in Oklahoma are deemedjust and reasonable under Oklahoma law unless challenged in a complaint. Wecannot predict whether such complaint will be filed against us or whether theOCC will change its regulation of these rates.

*GatheringPipeline Regulation.**  *Section 1(b) ofthe NGA exempts natural gas gathering facilities from the jurisdiction of theFERC. We own a number of intrastate natural gas pipelines in Texas that webelieve would meet the traditional tests FERC has used to establish a pipeline’sstatus as a gatherer not subject to FERC jurisdiction. We also believe that thepipeline facilities acquired in the ScissorTail Acquisition meet thetraditional tests FERC has used to establish a pipeline’s status as a gatherernot subject to FERC jurisdiction. However, the distinction betweenFERC-regulated transmission services and federally unregulated gatheringservices is the subject of regular litigation, so the classification andregulation of some of our gathering facilities may be subject to change basedon future determinations by FERC and the courts. State regulation of gatheringfacilities generally includes various safety, environmental and, in somecircumstances, nondiscriminatory take requirements and complaint-based rateregulation.

We are currently subject to state ratable take andcommon purchaser statutes in Texas, and are also subject to state ratable takeand common purchaser statutes in Oklahoma as a result of the ScissorTailAcquisition. The ratable take statutes generally require gatherers to take,without undue discrimination, natural gas production that may be tendered tothe gatherer for handling. Similarly, common purchaser statutes generallyrequire gatherers to purchase without undue discrimination in favor of oneproducer over another producer or one source of supply over another source ofsupply. These statutes have the effect of restricting our right as an owner ofgathering facilities to decide with whom we contract to purchase or transportnatural gas.

Natural gas gathering may receive greater regulatoryscrutiny at both the state and federal levels now that the FERC has taken aless stringent approach to regulation of the gathering activities of interstatepipeline transmission companies and a number of such companies have transferredgathering facilities to unregulated affiliates. For example, the TRRC hasapproved changes to its regulations governing transportation and gatheringservices performed by intrastate pipelines and gatherers, which prohibit suchentities from unduly discriminating in favor of their affiliates. Our gatheringoperations could be adversely affected should they be subject in the future tothe application of state or federal regulation of rates and services. Ourgathering operations also may be or become subject to safety and operationalregulations relating to the design, installation, testing, construction,operation, replacement and management of gathering facilities. Additional rules andlegislation pertaining to these matters are considered or adopted from time totime. We cannot predict what effect, if any, such changes might have on ouroperations, but the industry could be required to incur additional capitalexpenditures and increased costs depending on future legislative and regulatorychanges.

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*Sales of Natural Gas.**  *The price at which we buy and sellnatural gas currently is not subject to federal regulation and, for the mostpart, is not subject to state regulation. Our sales of natural gas are affectedby the availability, terms and cost of pipeline transportation. As noted above,the price and terms of access to pipeline transportation are subject toextensive federal and state regulation. FERC is continually proposing andimplementing new rules and regulations affecting those segments of the naturalgas industry, most notably interstate natural gas transmission companies thatremain subject to FERC’s jurisdiction. These initiatives also may affect theintrastate transportation of natural gas under certain circumstances. Thestated purpose of many of these regulatory changes is to promote competitionamong the various sectors of the natural gas industry, and these initiativesgenerally reflect more light-handed regulation. We cannot predict the ultimateimpact of these regulatory changes to our natural gas marketing operations, andwe note that some of FERC’s more recent proposals may adversely affect theavailability and reliability of interruptible transportation service oninterstate pipelines. We do not believe that we will be affected by any suchFERC action materially differently than other natural gas marketers with whomwe compete.

**Environmental Matters**

The operation ofpipelines, plants and other facilities for gathering, compressing, treating,processing, or transporting natural gas, natural gas liquids and other productsis subject to stringent and complex laws and regulations pertaining to health,safety and the environment. As an owner or operator of these facilities, wemust comply with these laws and regulations at the federal, state and locallevels. These laws and regulations can restrict or impact our businessactivities in many ways, such as:

·       restrictingthe way we can handle or dispose of our wastes;

·       limitingor prohibiting construction and operating activities in sensitive areas such aswetlands, coastal regions, or areas inhabited by endangered species;

·       requiringremedial action to mitigate pollution conditions caused by our operations orattributable to former operators; and

·       enjoiningthe operations of facilities deemed in non-compliance with permits issuedpursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations mayresult in the assessment of administrative, civil and criminal penalties, theimposition of remedial requirements, and the issuance of orders enjoiningfuture operations. Certain environmental statutes impose strict, joint andseveral liability for costs required to clean up and restore sites wheresubstances or wastes have been disposed or otherwise released. Moreover, it isnot uncommon for neighboring landowners and other third parties to file claimsfor personal injury and property damage allegedly caused by the release ofsubstances or wastes into the environment.

We believe that our operations are in substantialcompliance with applicable environmental laws and regulations and thatcompliance with existing federal, state and local environmental laws andregulations will not have a material adverse effect on our business, financialposition or results of operations. We cannot assure you that future events,such as changes in existing laws, the promulgation of new laws, or thedevelopment or discovery of new facts or conditions will not cause us to incursignificant costs. Nevertheless, the trend in environmental regulation is toplace more restrictions and limitations on activities that may affect theenvironment. As a result, there can be no assurance as to the amount or timingof future expenditures for environmental compliance or remediation, and actualfuture expenditures may be different from the amounts we currently anticipate.

The following is a discussion of certainenvironmental, health and safety laws and regulations that relate to ouroperations.

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*HazardousWaste.**  *Ouroperations generate wastes, including some hazardous wastes, that are subjectto the federal Resource Conservation and Recovery Act, as amended, or RCRA, andcomparable state laws, which impose detailed requirements for the handling,storage, treatment and disposal of hazardous and solid waste. RCRA currentlyexempts many natural gas gathering and field processing wastes fromclassification as hazardous waste. Specifically, RCRA excludes from thedefinition of hazardous waste produced waters and other wastes associated withthe exploration, development, or production of crude oil and natural gas. However,these oil and gas exploration and production wastes may still be regulatedunder state law or the less stringent solid waste requirements of RCRA. Moreover,ordinary industrial wastes such as paint wastes, waste solvents, laboratorywastes, and waste compressor oils may be regulated as hazardous waste. Thetransportation of natural gas in pipelines may also generate some hazardouswastes that are subject to RCRA or comparable state law requirements.

*SiteRemediation.**  *TheComprehensive Environmental Response, Compensation and Liability Act of 1980,as amended, or CERCLA, also known as “Superfund,” and comparable state lawsimpose liability, without regard to fault or the legality of the original conduct,on certain classes of persons responsible for the release of hazardoussubstances into the environment. Such classes of persons include the currentand past owners or operators of sites where a hazardous substance was released,and companies that disposed or arranged for disposal of hazardous substances atoffsite locations such as landfills. Although petroleum as well as natural gasis excluded from CERCLA’s definition of “hazardous substance,” in the course ofour ordinary operations we will generate wastes that may fall within thedefinition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to takeactions in response to threats to the public health or the environment and toseek to recover from the responsible classes of persons the costs they incur. UnderCERCLA, we could be subject to joint and several, strict liability for thecosts of cleaning up and restoring sites where hazardous substances have beenreleased, for damages to natural resources, and for the costs of certain healthstudies.

We currently own or lease, and have in the past ownedor leased, numerous properties that for many years have been used for themeasurement, gathering, field compression and processing of natural gas.Although we used operating and disposal practices that were standard in theindustry at the time, petroleum hydrocarbons or wastes may have been disposedof or released on or under the properties owned or leased by us or on or underother locations where such substances have been taken for disposal. In fact,there is evidence that petroleum spills or releases have occurred at some ofthe properties owned or leased by us. In addition, some of these propertieshave been operated by third parties or by previous owners whose treatment anddisposal or release of petroleum hydrocarbons or wastes was not under ourcontrol. These properties and the substances disposed or released on them maybe subject to CERCLA, RCRA and analogous state laws. Under such laws, we couldbe required to remove previously disposed wastes (including waste disposed ofby prior owners or operators), remediate contaminated property (includinggroundwater contamination, whether from prior owners or operators or otherhistoric activities or spills), or perform remedial plugging or pit closureoperations to prevent future contamination.

*AirEmissions.**  *Ouroperations are subject to the federal Clean Air Act, as amended, and comparablestate laws and regulations. These laws and regulations regulate emissions ofair pollutants from various industrial sources, including our processing plantsand compressor stations, and also impose various monitoring and reportingrequirements. Such laws and regulations may require that we obtain pre-approvalfor the construction or modification of certain projects or facilities expectedto produce air emissions or result in the increase of existing air emissions,obtain and strictly comply with air permits containing various emissions andoperational limitations, or utilize specific emission control technologies tolimit emissions. Our failure to comply with these requirements could subject usto monetary penalties, injunctions, conditions or restrictions on operations,and potentially criminal enforcement actions. We likely will be required toincur certain capital expenditures in the future for air pollution controlequipment in connection with obtaining and maintaining operating permits andapprovals for air emissions. We 

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believe, however, that ouroperations will not be materially adversely affected by such requirements, andthe requirements are not expected to be any more burdensome to us than to anyother similarly situated companies.

*WaterDischarges.**  *Ouroperations are subject to the Federal Water Pollution Control Act of 1972, asamended, also known as the Clean Water Act, and analogous state laws andregulations. These laws and regulations impose detailed requirements and strictcontrols regarding the discharge of pollutants into state and federal waters. Thedischarge of pollutants, including discharges resulting from a spill or leakincident, is prohibited unless authorized by a permit or other agency approval.The Clean Water Act and regulations implemented thereunder also prohibitdischarges of dredged and fill material in wetlands and other waters of theUnited States unless authorized by an appropriately issued permit. Anyunpermitted release of pollutants from our pipelines or facilities could resultin administrative, civil and criminal penalties as well as significant remedialobligations.

*PipelineSafety.**  *Ourpipelines are subject to regulation by the U.S. Department of Transportation,or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, orthe NGPSA, pursuant to which the DOT has established requirements relating tothe design, installation, testing, construction, operation, replacement andmanagement of pipeline facilities. The NGPSA covers the pipeline transportationof natural gas and other gases, and the transportation and storage of liquefiednatural gas (LNG) and requires any entity that owns or operates pipelinefacilities to comply with the regulations under the NGPSA, to permit access toand allow copying of records and to make certain reports and provideinformation as required by the Secretary of Transportation. We believe that ourpipeline operations are in substantial compliance with existing NGPSArequirements; however, due to the possibility of new or amended laws andregulations or reinterpretation of existing laws and regulations, futurecompliance with the NGPSA could result in increased costs.

The DOT, through the Office of Pipeline Safety,recently finalized a series of rules intended to require pipelineoperators to develop integrity management programs for gas transmissionpipelines that, in the event of a failure, could affect “high consequenceareas.” “High consequence areas” are currently defined as areas with specifiedpopulation densities, buildings containing populations of limited mobility, andareas where people gather that are located along the route of a pipeline.Similar rules are already in place for operators of hazardous liquidpipelines. The Texas Railroad Commission, or TRRC and the Oklahoma CorporationCommission or OCC, have adopted similar regulations applicable to intrastategathering and transmission lines. Compliance with these existing rules hasnot had a material adverse effect on our operations but there is no assurancethat this trend will continue in the future.

*Employee Health and Safety.**  *We are subject to the requirementsof the Occupational Safety and Health Act, as amended, referred to as OSHA, andcomparable state laws that regulate the protection of the health and safety ofworkers. In addition, the OSHA hazard communication standard requires thatinformation be maintained about hazardous materials used or produced in ouroperations and that this information be provided to employees, state and localgovernment authorities and citizens.

**Office Facilities**

We occupy approximately15,500 square feet of space at our executive offices in Houston, Texas under alease expiring on May 12, 2012 and are in the process of adding anadditional 15,500 square feet of office space under this lease. At theexpiration of the primary term, we have an option to renew this lease for anadditional five years at the then prevailing market rates. We also occupyapproximately 10,000 square feet of office space in Tulsa, Oklahoma whichserves as the executive offices for our ScissorTail subsidiary. The Tulsa leaseis for a five-year term and provides us with a five-year renewal option at thenprevailing market rates. We additionally lease certain of our field officefacilities and certain of our owned office facilities are located on landleased by us or on land subject to a permanent easement. While we may requireadditional 

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officespace as our business expands, we believe that our existing facilities areadequate to meet our needs for the immediate future and that additionalfacilities will be available on commercially reasonable terms as needed.

**Employees**

As of December 31,2005, we, through our subsidiaries, CPNO Services, L.P. and ScissorTail, had188 full-time employees and 4 part-time employees and Copano/Operations, Inc.(“Copano Operations”) employed 13 full-time employees and one part-timeemployee on our behalf. None of our employees are covered by collectivebargaining agreements. We consider our relations with these employees, withCopano Operations and with those Copano Operations’ employees providing servicesto us to be good. In exchange for providing general and administrative servicesto us, including employing certain personnel on our behalf, we are required toreimburse Copano Operations for its costs and expenses. To the extent theseemployees provide services on our behalf, we refer to them as our employees. A brief description of our general andadministrative services agreement will be contained in our proxy statement,certain parts of which are incorporated by reference into Part III of thisAnnual Report.

**Available Information**

We file annual, quarterly and other reports and otherinformation with the Securities and Exchange Commission, (“SEC”) under theSecurities Exchange Act of 1934 (the “Exchange Act”). You may read and copy anymaterials that we file with the SEC at the SEC’s Public Reference Room at100 F Street, NE, Washington, DC 20549. You may obtain additional informationabout the Public Reference Room by calling the SEC at 1-800-SEC-0330.In addition, the SEC maintains an Internet site (http://www.sec.gov) thatcontains reports, proxy and information statements, and other informationregarding issuers that file electronically with the SEC, including us.

We also make availablefree of charge on or through our Internet website (http://www.copanoenergy.com)or through our Investor Relations group (713-621-9545) our AnnualReports on Form 10-K, Quarterly Reports on Form 10-Q,Current Reports on Form 8-K, and other information statements and,if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) ofthe Exchange Act as soon as reasonably practicable after we electronically filesuch material with, or furnish it to, the SEC.

**Item 1A.**                RiskFactors

*You should consider carefully the risks anduncertainties described below and other information in this Annual Report,including the financial statements and related notes. While these are the risksand uncertainties we believe are most important, you should know that they arenot the only risks or uncertainties facing us or which may adversely affect ourbusiness. If any of the following risks or uncertainties were to occur, ourbusiness, financial condition or results of operation could be adverselyaffected.*

**Risks Related to Our Business**

***If the ScissorTailAcquisition or future acquisitions do not perform as expected, our futurefinancial performance may be negatively impacted.***

The ScissorTail Acquisition more than doubled the sizeof our company and significantly diversified the geographic areas in which weoperate. We cannot assure you that we will achieve the desired profitabilityfrom ScissorTail or any other acquisitions we may complete in the future. Inaddition, failure to successfully assimilate future acquisitions couldadversely affect our financial condition and results of operations.

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Our acquisitionsinvolve numerous risks, including:

·       operatinga significantly larger combined organization and adding operations;

·       difficultiesin the assimilation of the assets and operations of the acquired businesses,especially if the assets acquired are in a new business segment or geographicarea;

·       therisk that natural gas reserves expected to support the acquired assets may notbe of the anticipated magnitude or may not be developed as anticipated;

·       theloss of significant producers or markets or key employees from the acquiredbusinesses;

·       thediversion of management’s attention from other business concerns;

·       thefailure to realize expected profitability or growth;

·       thefailure to realize any expected synergies and cost savings;

·       coordinatinggeographically disparate organizations, systems and facilities; and

·       coordinatingor consolidating corporate and administrative functions.

Further, unexpected costsand challenges may arise whenever businesses with different operations ormanagement are combined, and we may experience unanticipated delays inrealizing the benefits of an acquisition. If we consummate any futureacquisition, our capitalization and results of operation may changesignificantly, and you may not have the opportunity to evaluate the economic,financial and other relevant information that we will consider in evaluatingfuture acquisitions.

***Our acquisition ofScissorTail could expose us to potential significant liabilities.***

In connection with theScissorTail Acquisition, we purchased all of the limited liability companyinterests of ScissorTail rather than just its assets. As a result, we purchasedthe liabilities of ScissorTail, including unknown and contingent liabilities. Weperformed due diligence in connection with the ScissorTail Acquisition andattempted to verify the representations of ScissorTail management, but theremay be pending, threatened, contemplated or contingent claims againstScissorTail related to environmental, title, regulatory, litigation or othermatters of which we are unaware. Although the former owners of ScissorTail haveagreed to indemnify us on a limited basis against some of these liabilities,there is a risk that we could ultimately be liable for some or all of theseindemnified liabilities, which could materially adversely affect our operationsand cash available for distribution to unitholders.

***Our substantialdebt could limit our operating flexibility and impair our ability to fulfillour debt obligations.***

We have substantial indebtedness. As of December 31,2005, we had total indebtedness of $398.0 million and availability under oursenior secured revolving credit facility of approximately $122.0 million.

Subject to therestrictions governing our indebtedness and other financial obligations and theIndenture, we may incur significant additional indebtedness and other financialobligations. Our substantial indebtedness and other financial obligations couldhave important consequences. For example, it could:

·       impairour ability to obtain additional financing in the future for working capital,capital expenditures, acquisitions, general company purposes or other purposes;

·       resultin higher interest expense in the event of increases in interest rates sincesome of our debt is, and will continue to be, at variable rates of interest;

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·       havea material adverse effect on us if we fail to comply with financial andrestrictive covenants in our debt agreements and an event of default occurs asa result of that failure that is not cured or waived;

·       requireus to dedicate a substantial portion of our cash flow to payments on ourindebtedness and other financial obligations, thereby reducing the availabilityof our cash flow to fund working capital, capital expenditures and other generalcompany requirements;

·       limitour flexibility in planning for, or reacting to, changes in our business andthe industry in which we operate; and

·       placeus at a competitive disadvantage compared to our competitors that haveproportionately less debt.

If we are unable to meetour debt service obligations and other financial obligations, we could beforced to restructure or refinance our indebtedness, seek additional equitycapital or sell assets. We may be unable to obtain such financing or equitycapital or sell assets on satisfactory terms, if at all.

***Restrictivecovenants in the agreements governing our indebtedness may reduce our operatingflexibility.***

Our senior securedcredit facility and other future indebtedness as well as the Indenturegoverning the Senior Notes contain various covenants that limit our ability andthe ability of our specified subsidiaries to, among other things:

·       sellassets;

·       paydistributions on, redeem or repurchase our equity interests or redeem orrepurchase our subordinated debt, if any;

·       makeinvestments;

·       incuror guarantee additional indebtedness or issue preferred units;

·       createor incur certain liens;

·       enterinto agreements that restrict distributions or other payments from ourrestricted subsidiaries to us;

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

·       engagein transactions with affiliates;

·       createunrestricted subsidiaries; and

·       enterinto sale and leaseback transactions.

Additionally, our senior secured revolving creditfacility contains covenants that require us to maintain specified financialratios and satisfy other financial conditions. These restrictive covenants inour senior secured revolving credit facility and in the Indenture could limitour ability and the ability of our subsidiaries to obtain future financings,make needed capital expenditures, withstand a future downturn in our businessor the economy in general, conduct operations or otherwise take advantage ofbusiness opportunities that may arise. We may be unable to comply with thesecovenants. Any future breach of any of these covenants could result in adefault under the terms of our senior secured revolving credit facility or theIndenture, which could result in acceleration of our debt and other financialobligations. If we were unable to repay those amounts, the lenders couldinitiate a bankruptcy proceeding or liquidation proceeding or proceed againstany collateral.

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***Our success willdepend on our ability to continually obtain new sources of natural gas supply,and any decrease in supplies of natural gas could adversely affect our revenuesand operating income.***

Our gathering and transmission pipeline systems areconnected to natural gas reserves and wells, for which the production willnaturally decline over time, which means that our cash flows associated withthese wells will also decline over time. To maintain or increase throughputlevels on our pipeline systems and our processing plants, we must continuallyobtain new natural gas supplies. We may not be able to obtain additionalcontracts for natural gas supplies. The primary factors affecting our abilityto connect new supplies of natural gas and attract new customers to ourgathering and transmission lines include: (1) the level of successfuldrilling activity near our gathering systems and (2) our ability tocompete for the commitment of such additional volumes to our systems.

Fluctuations in energy prices can greatly affectproduction rates and investments by third parties in the development of newnatural gas reserves. Drilling activity generally decreases as natural gasprices decrease. We will have no control over the level of drilling activity inthe areas of our operations, the amount of reserves underlying the wells or therate at which production from a well will decline. In addition, we will have nocontrol over producers or their production decisions, which are affected by,among other things, prevailing and projected energy prices, demand forhydrocarbons, the level of reserves, geological considerations, governmentalregulations and the availability and cost of capital.

We will face strong competition in acquiring newnatural gas supplies. Competitors of our pipeline operations include majorinterstate and intrastate pipelines, and other natural gas gatherers. Competitionfor natural gas supplies is primarily based on the location of pipelinefacilities, pricing arrangements, reputation, efficiency, flexibility andreliability. Our major competitors for natural gas supplies and markets in ourTexas Gulf Coast Pipelines segment include Enterprise Products Partners L.P.,Lobo Pipeline Company (an affiliate of ConocoPhillips), KMTP, Duke Energy FieldServices, Crosstex Energy, L.P., and Houston Pipe Line Company, an affiliate ofEnergy Transfer Partners, L.P. Our Texas Gulf Coast Processing segment’sprimary competitors are Enterprise, ExxonMobil and Duke Energy Field Services. Theprimary competitors for our Mid-Continent Operations business includeCenterPoint, Duke Energy Field Services, Enogex Inc., an affiliate of OGEEnergy Corp., and Enerfin Resources Company. Many of our competitors havegreater financial resources than we have.

If we are unable to maintainor increase the throughput on our pipeline systems because of decreaseddrilling activity in the areas in which we operate, decreased production fromthe wells connected to our systems or an inability to connect new supplies ofgas and attract new customers to our gathering and transmission lines, then ourbusiness and financial results or our ability to achieve our growth strategycould be materially adversely affected. Please read “Business—Mid-ContinentOperations Natural Gas Supply” and “Business—Texas Gulf Coast Natural GasSupply” elsewhere in this Annual Report for more information on our access tonatural gas suppliers.

***If KMTP’sLaredo-to-Katy pipeline becomes unavailable to transport natural gas to or fromour Houston Central Processing Plant for any reason, then our cash flow andrevenue could be adversely affected.***

Our ability to contract for natural gas supplies inthe Texas Gulf Coast region will often depend on our ability to deliver gas toour Houston Central Processing Plant and downstream markets. If we are unableto deliver natural gas to this processing plant or to downstream markets, thenour ability to contract for natural gas supplies could be hindered, and ourcash flow and revenue would likely be adversely affected. For the year ended December 31,2005, approximately 51% of the total natural gas delivered by our pipelines wasdelivered to KMTP. We deliver this natural gas to KMTP in order to transport itto our Houston Central Processing Plant, which straddles KMTP’s Laredo-to-Katy pipeline.Depending on the supply of residue gas at our processing plant and natural gasmarket conditions, we may sell natural gas to KMTP or to other shippers thattransport natural gas through KMTP’s Laredo-to-Katy pipeline. 

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Additionally, we may useKMTP’s Laredo-to-Katy pipeline to transport natural gas to our pipelineslocated in the Upper Gulf Coast Region of our Texas Gulf Coast Pipelinessegment and to downstream markets.

If KMTP’s pipeline were tobecome unavailable for any reason, the volumes transported to our HoustonCentral Processing Plant would be reduced substantially, and our cash flows andrevenues from our processing business could be adversely affected. In addition,many producers that use our Texas Gulf Coast gathering systems have natural gascontaining NGLs that must be conditioned or processed in order to meetdownstream market quality specifications. If we were unable to ship suchnatural gas to our Houston Central Processing Plant for processing orconditioning, and, if required, treating, we would need to arrange fortransportation through other pipelines that could provide these services. Alternatively,we might be required to lease smaller conditioning, and possibly treating,facilities in order to deliver to other pipelines having restrictive naturalgas quality specifications.

***We generally do notobtain independent evaluations of natural gas reserves dedicated to ourpipeline systems; therefore, volumes of natural gas transported on our pipelinesystems in the future could be less than we anticipate, which may cause ourrevenues and operating income to be less than we expect.***

We generally do not obtainindependent evaluations of natural gas reserves connected to our pipelinesystems due to the unwillingness of producers to provide reserve information aswell as the cost of such evaluations. Accordingly, we do not have estimates oftotal reserves dedicated to our systems or the anticipated life of suchreserves. If the total reserves or estimated life of the reserves connected toour pipeline systems is less than we anticipate and we are unable to secureadditional sources of natural gas, then the volumes of natural gas transportedon our pipelines in the future could be less than we anticipate. A decline inthe volumes of natural gas transported on our pipeline systems may cause ourrevenues to be less than we expect.

***We are exposed tothe credit risk of our customers and counterparties, and a general increase inthe nonpayment and nonperformance by our customers could have an adverse impacton our financial condition and results of operations.***

Risks of nonpayment andnonperformance by our customers are a major concern in our business. We aresubject to risks of loss resulting from nonpayment or nonperformance by ourcustomers. Any increase in the nonpayment and nonperformance by our customerscould have an adverse impact on our operating results and could adverselyimpact our liquidity.

***Our profitabilitydepends upon prices and market demand for natural gas and NGLs, which arebeyond our control and have been volatile.***

Our profitability is affected by prevailing NGL andnatural gas prices and we are subject to significant risks due to fluctuationsin commodity prices. These risks are based primarily upon two components of ourbusiness: (1) processing or conditioning at our processing plants, and (2) purchasingand selling volumes of natural gas at index-related prices.

The profitability of our Texas Gulf Coast Processingsegment is affected by the relationship between natural gas prices and NGLprices. When natural gas prices are low relative to NGL prices, it is moreprofitable for us to process the natural gas than to condition it. When naturalgas prices are high relative to NGL prices, we have the flexibility tocondition natural gas at the Houston Central Processing Plant rather than fullyprocess it, but the resulting margins are less. Accordingly, if natural gasprices remain high relative to NGL prices for extended periods of time, thenour results of operations could be adversely impacted.

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The margins we realize from purchasing and selling aportion of the natural gas that we will deliver through our Texas Gulf CoastPipeline systems decrease in periods of low natural gas prices because suchgross margins are based primarily on a percentage of the index price. For theyear ended December 31, 2005, approximately 96% of our natural gaspurchased by our Texas Gulf Coast Pipelines segment was purchased with apercentage of relevant index pricing component. Accordingly, a decline in the priceof natural gas could have an adverse impact on our results of operations fromour Texas Gulf Coast Pipelines business.

The profitability of our Mid-Continent Operationssegment is affected primarily by the level of NGL and natural gas prices. Becausewe generally receive a percentage of the sales proceeds of any NGLs extractedfrom the natural gas we gather in our Mid-Continent Operations segment as wellas a percentage of the sales proceeds of the residue gas remaining after theNGL extraction, our Mid-Continent Operations segment operations’ profitabilityincreases with higher commodity prices and decreases with a fall in commodityprices.

In the past, the prices of natural gas and NGLs havebeen extremely volatile, and we expect this volatility to continue. Forexample, during the years ended December 31, 2004 and 2005, the HoustonShip Channel, or HSC, natural gas index price ranged from a high of $7.32 perMMBtu to a low of $4.88 per MMBtu and from a high of $10.92 per MMBtu to a lowof $5.74 per MMBtu, respectively. A composite of the Oil Price InformationService, or OPIS, Mt. Belvieu monthly average NGL price based upon our averageNGL composition during the years ended December 31, 2004 and 2005 rangedfrom a high of approximately $0.855 per gallon to a low of approximately $0.569per gallon and from a high of approximately $1.116 per gallon to a low ofapproximately $0.729 per gallon, respectively.

We will seek to maintain a position that issubstantially balanced between purchases and sales for future deliveryobligations. However, we may not be successful in balancing our natural gaspurchases and sales. In addition, a producer could fail to deliver contractedvolumes or deliver in excess of contracted volumes, or a consumer could takemore or less than contracted volumes. Any of these actions could cause animbalance in our natural gas purchases and sales. If our purchases and sales ofnatural gas are not balanced, we will face increased exposure to commodityprice risks, which could increase the volatility of our operating income.

The markets andprices for natural gas and NGLs depend upon many factors beyond our control. Thesefactors include demand for oil, natural gas and NGLs, which fluctuate withchanges in market and economic conditions and other factors, including:

·       theimpact of weather on the demand for oil and natural gas;

·       thelevel of domestic oil and natural gas production;

·       theavailability of imported oil and natural gas;

·       actionstaken by foreign oil and gas producing nations;

·       theavailability of local, intrastate and interstate transportation systems;

·       theavailability and marketing of competitive fuels;

·       theimpact of energy conservation efforts; and

·       the extent of governmentalregulation and taxation.

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***A change in the characterizationof some of our assets by federal, state or local regulatory agencies or achange in policy by those agencies may result in increased regulation of ourassets, which may cause our revenues to decline and operating expenses toincrease.***

Most of our Texas pipelines are gathering systems thathave been deemed non-utilities by the Railroad Commission of Texas, or TRRC. Throughthe ScissorTail Acquisition, we acquired gathering systems in Oklahoma that arenot subject to utility regulation by the Oklahoma Corporation Commission, orOCC. Under Texas law, non-utilities in Texas are not subject to general rateregulation by the TRRC. Under Oklahoma law, non-utilities in Oklahoma (such asScissorTail’s gathering systems) are not subject to general rate regulation bythe OCC. Should the status of these non-utility assets change, they wouldbecome subject to general rate regulation by the TRRC or OCC, which couldadversely affect the rates that we are allowed to charge our customers. Some ofour intrastate natural gas transmission pipelines are subject to regulation asa common purchaser and as a gas utility by the TRRC. The TRRC’s jurisdictionover these pipelines extends to both rates and pipeline safety. The rates wecharge for transportation services in Texas are deemed just and reasonableunder Texas law unless challenged in a complaint. Should a complaint be filedor should regulation become more active, our business could be adverselyaffected.

As a natural gas gatherer and intrastate pipelinecompany, we are exempt from Federal Energy Regulatory Commission, or FERC,regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation stillaffects our business and the market for our products. FERC’s policies andpractices across the range of its natural gas pipeline regulatory activities,including, for example, its policies on open access transportation, ratemaking,capacity release, and market center promotion, indirectly affect intrastatemarkets. In recent years, FERC has pursued pro-competitive policies in itsregulation of interstate natural gas pipelines. However, we cannot assure youthat FERC will continue this approach as it considers matters such as pipelinerates and rules and policies that may affect rights of access to naturalgas transportation capacity. In addition, the rates, terms and conditions ofsome of the transportation services we provide on our pipelines are subject toFERC regulation under Section 311 of the Natural Gas Policy Act.

Other state and localregulations also affect our business. Our gathering lines in Texas are subjectto ratable take and common purchaser statutes. The gathering facilities weacquired in the ScissorTail Acquisition are likewise subject to ratable takeand common purchaser statutes in Oklahoma. Ratable take statutes generallyrequire gatherers to take, without undue discrimination, natural gas productionthat may be tendered to the gatherer for handling. Similarly, common purchaserstatutes generally require gatherers to purchase without undue discriminationas to source of supply or producer. These statutes restrict our right as anowner of gathering facilities to decide with whom we contract to purchase ortransport natural gas. Federal law leaves any economic regulation of naturalgas gathering to the states. Texas and Oklahoma have adopted complaint-basedregulation of natural gas gathering activities, which allows natural gasproducers and shippers to file complaints with state regulators in an effort toresolve grievances relating to natural gas gathering access and ratediscrimination. Please read “Business—Regulation.”

***Compliance withpipeline integrity regulations issued by the TRRC and OCC could result insubstantial expenditures for testing, repairs and replacement.***

The TRRC and OCC regulationsrequire periodic testing of all intrastate pipelines meeting certain size andlocation requirements. Our costs relating to compliance with the requiredtesting and repairs under the TRRC regulations was $0.8 million for yearended December 31, 2005. No costs were incurred relating to the pipelineintegrity testing requirements of the OCC for the year ended December 31,2005. If our pipelines fail to meet the safety standards mandated by the TRRCor OCC regulations, then we may be required to repair or replace sections ofsuch pipelines, the cost of which cannot be estimated at this time.

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***Because we handle natural gas and other petroleumproducts in our pipeline and processing businesses, we may incur significantcosts and liabilities in the future resulting from a failure to comply with newor existing environmental regulations or an accidental release of hazardoussubstances into the environment.***

The operations of ourgathering systems, plants and other facilities are subject to stringent andcomplex federal, state and local environmental laws and regulations. These lawsand regulations can restrict or impact our business activities in many ways,including restricting the manner in which we dispose of substances, requiringremedial action to remove or mitigate contamination, and requiring capitalexpenditures to comply with control requirements. Failure to comply with theselaws and regulations may trigger a variety of administrative, civil andcriminal enforcement measures, including the assessment of monetary penalties,the imposition of remedial requirements, and the issuance of orders enjoiningfuture operations. Certain environmental statutes impose strict, joint andseveral liability for costs required to clean up and restore sites wheresubstances and wastes have been disposed or otherwise released. Moreover, it isnot uncommon for neighboring landowners and other third parties to file claimsfor personal injury and property damage allegedly caused by the release ofhazardous substances or wastes into the environment.

There is inherent risk ofthe incurrence of environmental costs and liabilities in our business due toour handling of natural gas and other petroleum products, air emissions relatedto our operations, historical industry operations including releases ofsubstances into the environment, and waste disposal practices. For example, anaccidental release from one of our pipelines or processing facilities couldsubject us to substantial liabilities arising from environmental cleanup,restoration costs and natural resource damages, claims made by neighboringlandowners and other third parties for personal injury and property damage, andfines or penalties for related violations of environmental laws or regulations.Moreover, the possibility exists that stricter laws, regulations or enforcementpolicies could significantly increase our compliance costs and the cost of anyremediation that may become necessary. We may not be able to recover some orany of these costs from insurance. Please read “Business—Environmental Matters.”

***Expanding our business by constructing new assets willsubject us to risks that the project may not be completed on schedule, thecosts associated with the project may exceed our expectations and additionalnatural gas supplies may not be available following completion of the project,which could cause our revenues to be less than anticipated. Our operating cashflows from our capital projects also may not be immediate.***

One of the ways we maygrow our business is through the construction of additions to our existinggathering and transportation systems (including additional compression) andadditional modifications at our existing processing plants. The construction ofadditions or modifications to our existing gathering and transportation systemsand processing and treating facilities, and the construction of new gatheringand processing facilities, involve numerous regulatory, environmental,political, legal and operational uncertainties beyond our control and requirethe expenditure of significant amounts of capital. If we undertake theseprojects, they may not be completed on schedule or at all or at the budgetedcost. Moreover, our revenues may not increase immediately upon the expenditureof funds on a particular project. For instance, our non-wholly-owned operatingsubsidiary, Southern Dome is constructing a processing plant and pipelines tosupport anticipated future production in Oklahoma County, Oklahoma for whichsignificant cash flows will be expended. The cost of the project will be bornby us and the other member of Southern Dome with our share of the constructioncosts expected to be approximately $18.0 million. The design, construction,development and installation of the Southern Dome processing plant and pipelinesmay occur over an extended period of time, and we may not receive any materialincrease in operating cash flow from that project until after it is placed inservice. If we experience unanticipated or extended delays in generatingoperating cash flow from this or other projects, then we may need to reduce orreprioritize our capital budget to meet our capital requirements. We may alsorely on estimates of future production in our decision to construct additionsto our gathering and transportation systems, which 

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mayprove to be inaccurate because there are numerous uncertainties inherent inestimating quantities of future production. As a result, new facilities may notbe able to attract enough throughput to achieve our expected investment return.

***If the cost of renewing existing rights-of-wayincreases, it may have an adverse impact on our profitability. In addition, ifwe are unable to obtain new rights-of-way, then we may be unable to fullyexecute our growth strategy.***

The construction ofadditions to our existing gathering and transportation assets may require us toobtain new rights-of-way prior to constructing new pipelines. We may be unableto obtain such rights-of-way to connect new natural gas supplies to ourexisting gathering lines or capitalize on other attractive expansionopportunities. Additionally, it may become more expensive for us to obtain newrights-of-way or to renew existing rights-of-way. If the cost of renewingexisting rights-of-way increases, then our results of operations could be adverselyaffected. In addition, increased rights-of-way costs could impair our abilityto grow.

***Our business involves many hazards and operationalrisks, some of which may not be fully covered by insurance. If a significantaccident or event occurs that is not fully insured, our operations could betemporarily or permanently impaired, and our liabilities and expenses could besignificant.***

Ouroperations are subject to the many hazards inherent in the gathering,compression, treating, processing and transportation of natural gas and NGLs,including:

·       damageto pipelines, pipeline blockages and damage to related equipment andsurrounding properties caused by hurricanes, tornadoes, floods, fires, extremeweather conditions and other natural disasters and acts of terrorism;

·       inadvertentdamage from construction and farm equipment;

·       leaksof natural gas, NGLs and other hydrocarbons;

·       operatorerror; and

·       firesand explosions.

These risks could resultin substantial losses due to personal injury and/or loss of life, severe damageto and destruction of property and equipment and pollution or otherenvironmental damage and may result in curtailment or suspension of our relatedoperations. In addition, mechanical malfunctions, undetected ruptures inpipelines, faulty measurement or other errors may result in significant costsor lost revenues. Our operations are primarily concentrated in the Texas GulfCoast region and in central and eastern Oklahoma, and a natural disaster orother hazard affecting any of these areas could have a material adverse effecton our operations. For example, although we did not suffer significant damage,Hurricane Katrina and Hurricane Rita damaged gathering systems, processingfacilities, and NGL fractionators along the Gulf Coast in August and September 2005,respectively, which curtailed or suspended the operations of various energycompanies with assets in the region. There can be no assurance that insurancewill cover all damages and losses resulting from these types of natural disasters.We are not fully insured against all risks incident to our business. Inaccordance with typical industry practice, we do not have any propertyinsurance on any of our underground pipeline systems that would cover damage tothe pipelines. We are not insured against all environmental accidents thatmight occur, other than those considered to be sudden and accidental. Ourbusiness interruption insurance covers only losses arising from physical damageto our Houston Central Processing Plant, our Copano Bay pipeline system, ourPaden Plant and other systems without alternative interconnects. If asignificant accident or event occurs that is not fully insured, our operationscould be temporarily or permanently impaired, and our liabilities and expensescould be significant.

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***Due to our lack ofasset diversification, adverse developments in our gathering, transportation,processing and related businesses would have a significant impact on ourresults of operations.***

Substantially all of ourrevenues are generated from our gathering, dehydration, treating, conditioning,processing and transportation businesses, and as a result, our financialcondition depends upon prices of, and continued demand for, natural gas andNGLs. Furthermore, substantially all of our assets are located in Texas andOklahoma. Due to our lack of diversification in asset type and location, anadverse development in one of these businesses or in these areas would have asignificantly greater impact on our financial condition and results ofoperations than if we maintained more diverse assets.

***If we fail tomaintain an effective system of internal control over financial reporting, wemay not be able to accurately report our financial results or prevent fraud. Asa result, we may experience materially higher compliance costs.***

In early 2005, we began aprocess to document and evaluate our internal control over financial reportingin order to satisfy the requirements of Section 404 of the Sarbanes-OxleyAct of 2002 and the related regulations, which require annual managementassessments of the effectiveness of our internal control over financialreporting and a report by our independent registered public accounting firmaddressing these assessments. In this regard, management has dedicated internalresources, engaged outside consultants and adopted a detailed work plan to (i) assessand document the adequacy of our internal control over financial reporting, (ii) takesteps to improve control processes, where appropriate, (iii) validatethrough testing that controls are functioning as documented and (iv) implementa continuous review and reporting process for internal control over financialreporting. Our efforts to comply with Section 404 of the Sarbanes-OxleyAct of 2002 and the related regulations regarding our assessment of ourinternal control over financial reporting and our independent registered publicaccounting firm’s audit of that assessment have resulted, and are likely tocontinue to result, in increased expenses. We cannot be certain that thesemeasures will ensure that we maintain adequate controls over our financialprocesses and reporting in the future. Any failure to implement required newcontrols, or difficulties encountered in their implementation, could harm ouroperating results or cause us to fail to meet our reporting obligations. Ifcompliance with policies or procedures deteriorate and we fail to correct anyassociated issues in the design or operating effectiveness of our internalcontrol over financial reporting or fail to prevent fraud, current andpotential holders of our securities could lose confidence in our financialreporting, which could harm our business.

**Risks Related to Our Structure**

***Our limitedliability company agreement prohibits a unitholder who acquires 15% or more ofour common units without the approval of our Board of Directors from engagingin a business combination with us for three years. This provision coulddiscourage a change of control that our unitholders may favor, which couldnegatively affect the price of our common units.***

Our limited liabilitycompany agreement effectively adopts Section 203 of the Delaware GeneralCorporation Laws, or the DGCL. Section 203 of the DGCL as it applies to usprevents an interested unitholder, defined as a person who owns 15% or more ofour outstanding units, from engaging in business combinations with us for threeyears following the time such person becomes an interested unitholder.Section 203 broadly defines “business combination” to encompass a widevariety of transactions with or caused by an interested unitholder, includingmergers, asset sales and other transactions in which the interested unitholderreceives a benefit on other than a pro rata basis with other unitholders. Thisprovision of our limited liability company agreement could have ananti-takeover effect with respect to transactions not approved in advance byour Board of Directors, including discouraging takeover attempts that mightresult in a premium over the market price for our common units.

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***Our cap on certaingeneral and administrative expenses expires on December 31, 2007 (if notextended by our pre-IPO investors). Once the cap expires, our pre-IPO investorswill no longer be required to reimburse us for certain amounts in excess of thecap, which could materially reduce the cash available for distribution to ourunitholders.***

Pursuantto our limited liability company agreement, for three years beginning on January 1,2005, our pre-IPO investors agreed to reimburse us for our general andadministrative expenses in excess of the following levels (subject to certainlimitations):
| Year | ** ** | ** **                      | ** ** | ** ** | **General and Administrative Expense  Limitation** | ** ** |
|------|------------|---------------------------------|------------|------------|----------------------------------------------------|------------|
| 1    |       | $1.50 million  per quarter |
| 2    |       | $1.65 million  per quarter |
| 3    |       | $1.80 million  per quarter |

 

During this three-year period, the limitation ongeneral and administrative expenses for any quarter will be increased by 10% ofthe amount by which EBITDA for that quarter exceeds $5.4 million. Thislimitation, or cap, on general and administrative expenses excludes non-cashexpenses as well as expenses we may incur in connection with potentialacquisitions and capital improvements.

Once the cap expires, ourpre-IPO investors will no longer be required to reimburse us for certainamounts in excess of the cap. As a result, all of our general andadministrative expenses will be paid by us, which could materially reduce thecash available for distributions to our unitholders. For a detailed discussionof our cap on general and administrative expenses, please read Item 7 “Management’sDiscussion and Analysis of Financial Condition and Results of Operation—How WeEvaluate Our Operations—General and Administrative Expenses.”

***Distributions toour pre-IPO investors may be insufficient to allow them to reimburse us for allof our general and administrative expenses in excess of the cap, which couldmaterially reduce the cash available for distributions to our unitholders.***

Our pre-IPO investors haveagreed to reimburse us on a quarterly basis for our general and administrativeexpenses in excess of stated levels for a period of three years beginning on January 1,2005, subject to certain limitations. These reimbursements initially were made,without limitation, from an aggregate of $4 million held in escrowaccounts established immediately prior to our initial public offering with theproceeds of a distribution made by us to our pre-IPO investors. As a result ofreimbursement obligations for excess general and administrative expensesthrough September 30, 2005, these escrowed funds were exhausted. Anyfurther reimbursement obligation is limited solely to the amount ofdistributions attributable to the 5,557,378 common and subordinated units ownedby our pre-IPO investors immediately prior to our initial public offering. Basedon our current quarterly distribution rate of $0.55 per unit, thesedistributions would total, in the aggregate, $3.05 million quarterly and$12.2 million annually. If the distributions attributable to the commonand subordinated units held by our pre-IPO investors immediately prior to ourinitial public offering are insufficient to reimburse us for all of the excessgeneral and administrative expense, then amounts not reimbursed will be paid byus, which could have a material adverse effect on the cash available for distributionto our unitholders.

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***We may issueadditional common units without your approval, which would dilute your existingownership interests.***

During thesubordination period, we may issue up to 3,519,126 additional common unitswithout your approval. We may also issue an unlimited number of additionalcommon units or other equity securities of equal rank with the common units,without your approval, in a number of circumstances, such as:

·       theissuance of common units in connection with acquisitions or capitalimprovements that our management determines would increase cash flow fromoperations per unit on an estimated pro forma basis;

·       issuancesof common units to repay certain indebtedness, the cost of which to service isgreater than the distribution obligations associated with the units issued inconnection with the debt’s retirement;

·       theconversion of subordinated units into common units;

·       theconversion of units of equal rank with the common units into common units undersome circumstances;

·       theissuance of common units under our long-term incentive plan; or

·       theredemption of common units with the proceeds of a concurrent offering of commonunits.

After the end of the subordination period, we mayissue an unlimited number of limited liability company interests of any type,including common units, without the approval of our unitholders. Our limitedliability company agreement does not give the unitholders the right to approveour issuance at any time of equity securities ranking junior to the commonunits.

The issuance ofadditional common units or other equity securities of equal or senior rank willhave the following effects:

·       yourproportionate ownership interest in us will decrease;

·       theamount of cash available for distribution on each unit may decrease;

·       becausea lower percentage of total outstanding units will be subordinated units, therisk that a shortfall in the payment of the minimum quarterly distribution willbe borne by the common unitholders will increase;

·       therelative voting strength of each previously outstanding unit will bediminished; and

·       the market price of thecommon units may decline.

***Our limitedliability company agreement provides for a limited call right that may requireyou to sell your common units at an undesirable time or price.***

If, at any time, anyperson owns more than 90% of the common units then outstanding, such person hasthe right, but not the obligation, which it may assign to any of its affiliatesor to us, to acquire all, but not less than all, of the remaining common unitsthen outstanding at a price not less than the then-current market price of thecommon units. As a result, you may be required to sell your common units at anundesirable time or price and may therefore not receive any return on yourinvestment. You may also incur tax liability upon a sale of your units.

***Certain of ourinvestors may sell units in the public market, which could reduce the marketprice of our outstanding common units.***

Pursuant to our limitedliability company agreement and the Stakeholder’s Agreement dated July 30,2004 among us and our pre-IPO investors, we agreed to register for sale unitsreceived by affiliates of our 

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management,Credit Suisse and EnCap Investments in connection with our initial publicoffering, including 2,038,252 common units received upon the closing of the IPOand 3,519,125 common units to be issued upon the conversion of our subordinatedunits. Each subordinated unit will convert into one common unit at the end ofthe subordination period, which may be as early as the first quarter of 2007. Fora more detailed description of the circumstances under which the subordinatedunits will convert into common units, please read Item 5 “Market for Registrant’s CommonEquity, Related Unitholder Matters and Issuer Purchases of Equity Securities”of this Annual Report. We have also agreed to register (i) 6,203,216common units issued to private investors in connection with the ScissorTailAcquisition and (ii) 1,418,440 common units issued to private investors inDecember 2005 and January 2006. Pursuant to these obligations, weregistered an aggregate of 7,260,908 of these common units under a registrationstatement on Form S-3, which was declared effective by the SEC on January 26,2006. We are obligated to use reasonable efforts to cause the registration ofan additional 1,418,440 of the common units to be declared effective by April 28,2006. If investors holding these units were to dispose of a substantial portionof their units in the public market, it could temporarily reduce the marketprice of our outstanding common units.

**Tax Risks to Common Unitholders**

***Our tax treatmentdepends on our status as a partnership for federal income tax purposes, as wellas our not being subject to entity-level taxation by individual states. Ifthe IRS treats us as a corporation for tax purposes or we become subject toentity-level taxation, it would substantially reduce the amount of cashavailable for distribution to our unitholders.***

The after-tax benefit of an investment in our commonunits depends largely on our being treated as a partnership for federal incomepurposes. We have not requested, and do not plan to request, a ruling from theIRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal incometax purposes, we would pay federal income tax on our taxable income at thecorporate tax rates, currently at a maximum rate of 35%, and would likely paystate income tax at varying rates. Distributions to you would generally betaxed again as corporate distributions, and no income, gain, loss or deductionwould flow through to you. Because a tax would be imposed on us as acorporation, our cash available for distribution to our unitholders would besubstantially reduced. Therefore, our treatment as a corporation would resultin a material reduction in the anticipated cash flow and after-tax return toour unitholders and therefore would likely result in a substantial reduction inthe value of our common units.

Current law or ourbusiness may change so as to cause us to be treated as a corporation forfederal income tax purposes or otherwise subject us to entity-level taxation. Inaddition, because of widespread state budget deficits, several states areevaluating ways to subject partnerships and limited liability companies toentity-level taxation through the imposition of state income, franchise orother form of taxation. If any state were to impose a tax upon us as an entity,the cash available to us for distribution to you would be reduced. Our limitedliability company agreement provides that if a law is enacted or existing lawis modified or interpreted in a manner that subjects us to taxation as acorporation or otherwise subjects us to entity-level taxation for federal,state or local income tax purposes, then the minimum quarterly distributionamount will be adjusted to reflect the impact of that law on us.

***A successful IRScontest of the federal income tax positions we take may adversely affect themarket for our common units, and the costs of any contest will reduce cashavailable for distribution to our unitholders.***

We have not requested aruling from the IRS with respect to our treatment as a partnership for federalincome tax purposes or any other matter that affects us. The IRS may adoptpositions that differ from the positions we take. It may be necessary to resortto administrative or court proceedings to sustain 

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some orall of the positions we take. A court may disagree with some or all of thepositions we take. Any contest with the IRS may materially and adversely impactthe market for our common units and the price at which they trade. In addition,our costs of any contest with the IRS will result in a reduction in cashavailable for distribution to our unitholders and thus will be borne indirectlyby our unitholders.

***A unitholder willbe required to pay taxes on income from us even if the unitholder does notreceive any cash distributions from us.***

You will be required topay any federal income taxes and, in some cases, state and local income taxeson your share of our taxable income, whether or not you receive cashdistributions from us. You may not receive cash distributions from us equal toyour share of our taxable income or even equal to the tax liability thatresults from the taxation of your share of our taxable income.

***Tax-exempt entitiesand foreign persons face unique tax issues from owning common units that mayresult in adverse tax consequences to them.***

Investment in common unitsby tax-exempt entities, including employee benefit plans and individualretirement accounts (known as IRAs), and non-U.S. persons raises issues uniqueto them. For example, virtually all of our income allocated to organizationsexempt from federal income tax, including individual retirement accounts andother retirement plans, will be unrelated business taxable income and will betaxable to such a unitholder. Distributions to non-U.S. persons will be reducedby withholding taxes imposed at the highest effective applicable tax rate, andnon-U.S. persons will be required to file United States federal income taxreturns and pay tax on their share of our taxable income. If you are atax-exempt entity or a non-U.S. person, you should consult your tax advisorbefore investing in our units.

***We treat eachpurchaser of our common units as having the same tax benefits without regard tothe actual common units purchased. The IRS may challenge this treatment, whichcould adversely affect the value of the common units.***

Because we cannot matchtransferors and transferees of common units, we have adopted depreciation andamortization positions that may not conform with all aspects of existingTreasury Regulations. A successful IRS challenge to those positions couldadversely affect the amount of tax benefits available to our unitholders. Italso could affect the timing of these tax benefits or the amount of gain on thesale of common units and could have a negative impact on the value of ourcommon units or result in audits of and adjustments to our unitholders’ taxreturns.

***Unitholders may besubject to state and local taxes and return filing requirements.***

In addition to federalincome taxes, unitholders will likely be subject to other taxes, includingstate and local taxes, unincorporated business taxes and estate, inheritance orintangible taxes that are imposed by the various jurisdictions in which we dobusiness or own property now or in the future, even if our unitholders do notreside in any of those jurisdictions. Our unitholders will likely be requiredto file state and local income tax returns and pay state and local income taxesin some or all of these jurisdictions. Further, unitholders may be subject topenalties for failure to comply with those requirements. We currently dobusiness and own assets in Texas and Oklahoma. Although Texas does notcurrently impose a personal income tax, Oklahoma does and as we makeacquisitions or expand our business, we may do business or own assets in otherjurisdictions that impose a personal income tax. It is the responsibility ofeach unitholder to file all United States federal, state and local tax returnsthat may be required of such unitholder. Our counsel has not rendered anopinion on the state or local tax consequences of an investment in the commonunits.

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***The sale orexchange of 50% or more of our capital and profits interests during anytwelve-month period will result in the technical termination of our partnershipfor federal income tax purposes.***

We will be considered tohave technically terminated for federal income tax purposes if there is a saleor exchange of 50% or more of the total interests in our capital and profitswithin a twelve-month period. While we would continue our existence as aDelaware limited liability company, our technical termination would, amongother things result in the closing of our taxable year for all unitholders andcould result in a deferral of depreciation deductions allowable in computingour taxable income.

**Item 1B.**               UnresolvedStaff Comments

None.

**Item 2.**                        Properties

A description of ourproperties is contained in Item 1 “Business” of this Annual Report. Substantiallyall of our pipelines are constructed on rights-of-way granted by the apparentrecord owners of the property. Lands over which pipeline rights-of-way havebeen obtained may be subject to prior liens that have not been subordinated tothe right-of-way grants. We have obtained, where necessary, license or permitagreements from public authorities and railroad companies to cross over orunder, or to lay facilities in or along, waterways, county roads, municipalstreets, railroad properties and state highways, as applicable. In some cases,property on which our pipeline was built was purchased in fee.

Some of our leases, easements, rights-of-way, permits,licenses and franchise ordinances require the consent of the current landownerto transfer these rights, which in some instances is a governmental entity. Webelieve that we have obtained sufficient third-party consents, permitsand authorizations for the transfer of the assets necessary for us to operateour business in all material respects. With respect to any consents, permits orauthorizations that have not been obtained, we believe that the failure toobtain these consents, permits or authorizations will have no material adverseeffect on the operation of our business.

We believe that we havesatisfactory title to our assets. Title to property may be subject toencumbrances. We believe that none of these encumbrances will materiallydetract from the value of our properties or from our interest in theseproperties nor will they materially interfere with their use in the operationof our business.

**Item 3.**                        LegalProceedings

Although we may, fromtime-to-time, be involved in litigation and claims arising out of ouroperations in the normal course of business, we are not currently a party toany material legal proceedings. In addition, we are not aware of any materiallegal or governmental proceedings against us, or contemplated to be broughtagainst us, under the various environmental protection statutes to which we aresubject.

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**Item 4.**                        Submissionof Matters to a Vote of Security Holders

We held a specialmeeting of unitholders on October 27, 2005 at which two proposals wereconsidered. A brief description of each proposal and the voting resultsfollows:

Aproposal to (1) change the terms of our Class B units to provide thateach Class B unit would automatically convert into one of our common unitsand (2) issue 4,830,758 additional common units upon such conversion. The Class Bunits were issued by us to certain private investors to partially finance theScissorTail Acquisition.

| For         |   | 7,352,663 |   |
|-------------|--------|-----------|--------|
| Against     |   | 47,964    |   |
| Abstentions |   | 31,659    |   |

 

Aproposal to approve an amendment to our Long-Term Incentive Plan, or LTIP, to (i) increasethe total number of common units authorized to be issued under the LTIP to thelesser of (a) 2,500,000 units or (b) the number of units equal to 10%of the sum of total common units outstanding and the total number of commonunits that may be issued to the holders of any outstanding equity securitiesconvertible into common units, exclusive of outstanding awards under the LTIP,determined at the time of any award, (ii) provide that not more than 30%of the total number of common units authorized to be issued under the LTIP maybe delivered in payment of restricted units and/or phantom units, (iii) designateour consultants as a class eligible for awards under the LTIP and (iv) permitthe Compensation Committee of our Board of Directors, in its discretion, todelegate any of its administrative powers under the LTIP to our Chief ExecutiveOfficer (other than with respect to grants made to executive officers anddirectors).

| For         |   | 8,623,170 |   |
|-------------|--------|-----------|--------|
| Against     |   | 137,090   |   |
| Abstentions |   | 44,484    |   |

 

 

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**PART II**

**Item 5.**                        Marketfor Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchasesof Equity Securities

Our common units representing limited liabilitycompany interests in us are listed on The NASDAQ National Market, or NASDAQ,under the symbol “CPNO.”  On March 1,2006, the market price for our common units was $41.04 per unit and there wereapproximately 3,500 common unitholders, of which there were approximately 30common unitholders of record. Additionally, there were 17 unitholders of recordof our subordinated units. There is no established public trading market forour subordinated units.

Thefollowing table shows the high and low sales prices per common unit, asreported by NASDAQ, for the periods indicated:

| ** **                       | ** ** | **Common Unit  Price Range** | ** ** | **Cash  Distribution** | ** ** |
|----------------------------------|------------|----------------------------------------|------------|------------------------|------------|
| ** **                       | ** ** | **High**                               | ** ** | **Low**                | ** ** | **Paid Per Unit** | ** ** |
| **2005:**                        |       |                                   |       |                   |       |   |   |   |   |
| Quarter Ended  December 31  |       | $                                      | 39.90      |                   | $          | 34.10 |   |   | $ | 0.55 |   |   |
| Quarter Ended  September 30 |       | $                                      | 44.60      |                   | $          | 36.00 |   |   | $ | 0.50 |   |   |
| Quarter Ended  June 30      |       | $                                      | 36.90      |                   | $          | 27.76 |   |   | $ | 0.45 |   |   |
| Quarter Ended March 31      |       | $                                      | 31.48      |                   | $          | 25.47 |   |   | $ | 0.42 |   |   |
| **2004:**                        |       |                                   |       |                   |       |   |   |   |   |
| Quarter Ended  December 31  |       | $                                      | 28.75      |                   | $          | 23.06 |   |   | $ | 0.20 | (1) |   |

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(1)          The distribution for thequarter ended December 31, 2004 was paid on February 14, 2005 toholders of record as of the close of business on February 1, 2005 andreflected a pro rata portion of our $0.40 per unit minimum quarterlydistribution, covering the period from the November 15, 2004 closing ofour initial public offering through December 31, 2004.

Within 45 days after the end of each quarter, weintend to pay quarterly in arrears (in February, May, August and November ofeach year), to the extent we have sufficient available cash from operatingsurplus as defined in our limited liability company agreement, no less than theminimum quarterly distribution, or MQD, of $0.40 per unit (or $1.60 per year),to our common and subordinated unitholders of record on the applicable recorddate. During the subordination period (as described below), the common unitswill have the right to receive distributions of available cash from operatingsurplus in an amount equal to the MQD of $0.40 per quarter, plus any arrearagesin the payment of the MQD on the common units from prior quarters, before anydistributions of available cash from operating surplus may be made on thesubordinated units. In the event we do not have sufficient cash to pay ourdistributions as well as satisfy our other operational and financialobligations, our Board of Directors has the ability to reduce or eliminate thedistribution paid on our common and subordinated units so that we may satisfysuch obligations, including payments on our debt instruments.

Our available cash consists generally of all cash onhand at the end of the fiscal quarter, less retained cash reserves that our boarddetermines are necessary to a) provide for the proper conduct of our business;b) comply with applicable law, any of our debt instruments, or otheragreements; or (c) provide funds for distributions to our unitholders forany one or more of the next four quarters; plus all cash on hand for thequarter resulting from eligible working capital borrowings made after the endof the quarter on the date of determination of available cash. Operating surplus generally consists of cashon hand at the closing of our initial public offering, cash generated fromoperations after deducting related expenditures and other items, plus eligibleworking capital borrowings after theend of the quarter, plus $12.0 million, as adjusted for reserves. Wehave not established a credit facility that provides for the type of workingcapital borrowings that would be eligible, pursuant to our limited liabilitycompany agreement, to be considered available cash or operating surplusdistributable to our unitholders.

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Our Board of Directors has broad discretion toestablish cash reserves that it determines are necessary or appropriate toproperly conduct our business. These can include cash reserves for futurecapital and maintenance expenditures, reserves to stabilize distributions of cashto the unitholders, reserves to reduce debt, or, as necessary, reserves tocomply with the terms of any of our agreements or obligations.

On February 14, 2005, we paid cash distributionsof $2.1 million, or $0.20 per unit, which reflected a pro rata portion of ourMQD for the period from November 15, 2004 (the closing of our initialpublic offering) through December 31, 2004. On May 13, 2005, we paid$4.5 million of cash distributions representing $0.42 per unit, or $1.68 perunit annualized, for the three months ended March 31, 2005. On July 15,2005, our Board declared a cash distribution for the three months ended June 30,2005 of $0.45 per unit, or $1.80 per unit annualized, for all outstandingcommon and subordinated units. The distribution totaling $7.8 million was paidon August 15, 2005 to holders of record at the close of business on August 1,2005 and included 1,372,458 common units issued in connection with the closingof the ScissorTail Acquisition. This distribution amount also included a concurrentquarterly distribution of $.0495 per unit with respect to 4,830,758 Class Bunits issued in connection with the closing of the ScissorTail Acquisition. TheClass B unit distribution represented a quarterly distribution equal to110% of the per unit distribution received by the common units as required bythe terms of the Class B units. On October 27, 2005, our unitholdersapproved the conversion of each of the Class B units into one common unitand the issuance of 4,830,758 additional common units upon such conversion. On January 18,2006, our Board of Directors declared a cash distribution for the three monthsended December 31, 2005 of $0.55 per unit for all outstanding common andsubordinated units. The distribution totaling $10.1 million was paid on February 14,2006 to holders of record at the close of business on February 1, 2006 andincluded 1,418,440 common units issued in private placements to certain privateinvestors in December 2005 and January 2006.

Theamount of available cash from operating surplus needed to pay the currentdistribution of $0.55 per unit, or $2.20 per unit annualized, to our common andsubordinated unitholders is as follows (in thousands):

| ** **      | ** ** | **One Quarter** | ** ** | **Four Quarters** | ** ** |
|-----------------|------------|----------------------|------------|------------------------|------------|
| Common units(1) |       |                 | $          | 8,146                  |       |   |   | $ | 32,583 |   |   |
| Subordinated    |       |                 | 1,935      |                   |       |   | 7,742 |   |   |
| Total           |       |                 | $          | 10,081                 |       |   |   | $ | 40,325 |   |   |

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(1)          Includes restrictedcommon units issued under our LTIP. Distributions made on restricted unitsissued to date are subject to the same vesting provisions as the restrictedunits. As of February 1, 2006, we had 139,380 outstanding restrictedunits. Annual distributions related to these restricted units are approximately$0.3 million.

During the subordination period, the common units willhave the right to receive distributions of available cash from operatingsurplus in an amount equal to the MQD of $0.40 per quarter, plus any arrearagesin the payment of the MQD on the common units from prior quarters, before anydistributions of available cash from operating surplus may be made on thesubordinated units. The purpose of the subordinated units is to increase thelikelihood that during the subordination period there will be available cash tobe distributed on the common units.

The subordinationperiod will extend until the first day of any quarter beginning after December 31,2006 in which each of the following tests are met:

·       distributionsof available cash from operating surplus on each of the outstanding commonunits and subordinated units for two consecutive four-quarter periods immediatelypreceding that date equaled or exceeded the minimum quarterly distribution;

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·       the“adjusted operating surplus” as defined in our limited liability companyagreement generated during the two consecutive four-quarter periods immediatelypreceding that date equaled or exceeded the sum of the minimum quarterlydistributions on all of the outstanding common units and subordinated units;and

·       thereare no arrearages in payment of the minimum quarterly distribution on thecommon units.

Upon expiration of thesubordination period, all subordinated units will convert into common units ona one-for-one basis and will then participate, pro rata, with the other commonunits in distributions of available cash, and the common units will no longerbe entitled to arrearages.

***Securities Authorized for Issuance Under EquityCompensation Plans***

Thefollowing table sets forth certain information as of December 31, 2005regarding the LTIP, under which our common units are authorized for issuance toour employees, consultants, affiliates and directors through the exercise ofunit options.

| ** **                                            | ** ** | **Number of  Securities to be  Issued upon  Exercise/Vesting  of Outstanding  Options, Warrants  and Rights** | ** ** | **Weighted  Average  Exercise Price  of Outstanding  Options,  Warrants and  Rights** | ** ** | **Number of Units  Remaining  Available for  Future Issuance  Under Equity  Compensation  Plans  (Excluding Units  Reflected in  column (a))** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                            | ** ** | **(a)**                                                                                                                                          | ** ** | ** **                                                                                           | ** ** | ** **                                                                                                                                                                             | ** ** |
| Equity  compensation plans approved by unitholders(1) |       |                                                                                                                                             | 630,228    | (2)                                                                                                  |       |                                                                                                                                                                                   | $          | 30.18 |   |   |   | 640,930 | (3) |   |
| Equity compensation  plan not approved by unitholders |       |                                                                                                                                             | —     |                                                                                                 |       |                                                                                                                                                                                   | —     |   |   |   | — |   |   |
| Total(4)                                              |       |                                                                                                                                             | 630,228    |                                                                                                 |       |                                                                                                                                                                                   | $          | 30.18 |   |   |   | 640,930 |   |   |

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(1)          Our sole equitycompensation plan is our Long-Term Incentive Plan, which was approved by ourmembers prior to our initial public offering.

(2)          Includes 139,380 issuedand outstanding restricted common units and options to purchase 491,110 commonunits under our LTIP.

(3)          Determined by referenceto the formula described below.

(4)          Of the 491,110 unitoptions outstanding at December 31, 2005, 37,688 were immediatelyexercisable.

Our LTIP, adopted in November 2004, provides forthe grant of restricted units, phantom units, unit options and/or unitappreciation rights to our directors, employees and consultants and toemployees of our affiliates who perform services for us. For purposes of theplan, our affiliates include Copano Operations. The total number of commonunits authorized to be issued under the plan is limited to the lesser of (a) 2,500,000units or (b) the number of units equal to 10% of the sum of total commonunits outstanding and the total number of common units that may be issued tothe holders of any outstanding equity securities convertible into common units,exclusive of outstanding awards under the plan, determined at the time of anyaward, provided no more than 30% of the total number of common units authorizedto be issued under the plan may be delivered in payment of restricted unitsand/or phantom units. The plan is administered under the direction of theCompensation Committee of our Board of Directors.

Unit options are granted under our long-term incentiveplan and have an exercise price that may not be less than the fair market valueof the underlying units on the date of grant. In general, unit options grantedwill become exercisable over a period determined by our Compensation Committee.In addition, 

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unit options will becomeexercisable upon a change in control, unless provided otherwise by the CompensationCommittee.

Restricted units are awarded under our long-termincentive plan and are common units that vest over a period of time and thatduring such time are subject to forfeiture. In addition, restricted units willvest upon a change of control, unless provided otherwise by our CompensationCommittee. Distributions made on restricted units may be subjected to the samevesting provisions as the restricted units. The restricted units are intendedto serve as a means of incentive compensation for performance and not primarilyas an opportunity to participate in the equity appreciation of the common units.Therefore, plan participants will not pay any consideration for the commonunits they receive and we will receive no remuneration for the units. During2005, a total of 127,380 restricted common units were issued (net of forfeituresand vesting) to our directors and certain of our employees and employees of ouraffiliates.

For additional information regarding the LTIP, pleaseread Notes 2 and 9 of our consolidated financial statements included underItem 8 of this Annual Report.

Please read theinformation incorporated by reference under Item 12, “Security Ownershipof Certain Beneficial Owners and Management and Related Unitholder Matters” ofthis Annual Report, regarding securities authorized for issuance under ourequity compensation plans, which information is incorporated by reference intothis Item 5.

**IssuerPurchases of Equity Securities**

In connection with ourinitial public offering in November 2004, we used the net proceeds fromthe exercise of the underwriters’ over-allotment option to redeem 375,000common units from affiliates of Credit Suisse (formerly Credit Suisse FirstBoston Private Equity) and 375,000 common units from affiliates of EnCapInvestments. The redemption price for the common units was $18.60 per common unit,which was the initial public offering price to our public common unitholdersless underwriting discounts. There have been no other repurchases of our equitysecurities since our initial public offering in November 2004.

**RecentSales of Unregistered Securities**

On November 15, 2004, in connection with ourinitial public offering, all of our equity securities outstanding prior to ourinitial public offering were converted into our 2,038,582 common units and3,519,126 subordinated units, and allocated among our pre-offering unitholderspursuant to a pre-arranged formula. Each of these transactions was exempt fromregistration under Section 4(2) of the Securities Act as thetransaction did not involve a public offering.

In connection with our ScissorTail Acquisition on August 1,2005, we issued 1,372,458 common units and 4,830,758 Class B units to 13private investors for an aggregate purchase price of $175.0 million. On October 27,2005, our unitholders approved the conversion of each of the Class B unitsinto one common unit and the issuance of 4,830,758 additional common units uponsuch conversion. Each of these transactions was exempt from registration under Section 4(2) ofthe Securities Act as the transactions did not involve a public offering.

On December 30, 2005, we issued 709,200 commonunits and on January 3, 2006, we issued 709,200 common units to three privateinvestors for aggregate net proceeds of $50.0 million. The purchase price foreach common unit was $35.25. Each of these transactions was exempt fromregistration under Section 4(2) of the Securities Act as thetransactions did not involve a public offering.

There have been no othersales of unregistered securities within the past three years.

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**Item 6.**                        SelectedFinancial Data

**SelectedHistorical Consolidated Financial and Operating Data**

The following table shows selected historicalconsolidated financial and operating data of Copano Energy, L.L.C. for theperiods and as of the dates indicated. The selected historical consolidated financialdata for the years ended December 31, 2005, 2004, 2003, 2002 and 2001 arederived from the audited consolidated financial statements of Copano Energy,L.L.C.

The following table includes the following non-GAAPfinancial measures: (1) EBITDA and (2) total gross margin. We defineEBITDA as net income (loss) plus interest expense, provision for income taxesand depreciation and amortization expense. We define total gross margin as ourrevenue minus cost of sales. Cost of sales includes the following costs andexpenses: cost of natural gas and NGLs purchased by us from third parties, costof natural gas and NGLs purchased by us from affiliates, costs we pay thirdparties to transport our volumes and costs we pay our affiliates to transportour volumes. For a reconciliation of these non-GAAP financial measures totheir most directly comparable financial measures calculated and presented inaccordance with GAAP, please read page 52 of this Annual Report.

Wederived the information in the following table from, and that informationshould be read together with and is qualified in its entirety by reference to,our historical consolidated financial statements and the accompanying notesincluded in Item 8 of this Annual Report. The selected financial informationshould be read together with Item 7, “Management’s Discussion and Analysisof Financial Condition and Results of Operation.”

| ** **                                                | ** ** | **Year Ended December 31,**                        | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                                | ** ** | **2005(1)**                                                       | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                | ** ** | **(in thousands, except per unit data)** | ** ** |
| **Summary of Operations Data:**                           |       |                                                              |       |   |   |   |   |   |   |   |   |
| Revenues                                                  |       | $                                                                 | 747,743    |   | $ | 437,656 |   | $ | 384,571 |   | $ | 224,896 |   | $ | 160,369 |   |
| Cost of sales                                             |       | 643,652                                                           |       | 386,155 |   | 353,376 |   | 199,525 |   | 143,381 |   |
| Operations and  maintenance expenses                      |       | 18,459                                                            |       | 12,486 |   | 10,854 |   | 9,562 |   | 4,960 |   |
| Depreciation and  amortization                            |       | 17,052                                                            |       | 7,287 |   | 6,091 |   | 5,539 |   | 3,326 |   |
| General and  administrative expenses                      |       | 18,156                                                            |       | 9,217 |   | 5,849 |   | 4,177 |   | 2,171 |   |
| Taxes other than  income                                  |       | 1,178                                                             |       | 770 |   | 926 |   | 891 |   | 435 |   |
| Equity in (earnings)  loss from unconsolidated affiliates |       | (927                                                              | )          | (419 | ) | 127 |   | 584 |   | — |   |
| Operating income                                          |       | 50,173                                                            |       | 22,160 |   | 7,348 |   | 4,618 |   | 6,096 |   |
| Interest and  other financing costs                       |       | (20,461                                                           | )          | (23,160 | ) | (12,108 | ) | (6,360 | ) | (2,227 | ) |
| Interest income  and other                                |       | 640                                                               |       | 85 |   | 43 |   | 101 |   | 183 |   |
| Net income (loss)                                         |       | $                                                                 | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) | $ | (1,641 | ) | $ | 4,052 |   |
| Basic net income (loss) per unit:(2)                      |       | $                                                                 | 2.31       |   | $ | (0.35 | ) | $ | (6.21 | ) | $ | (6.77 | ) | $ | 2.25 |   |
| Diluted net income (loss) per unit:(2)                    |       | $                                                                 | 2.29       |   | $ | (0.35 | ) | $ | (6.21 | ) | $ | (6.77 | ) | $ | 2.25 |   |
| Cash distributions per common unit:(2)                    |       | $                                                                 | 1.57       |   | $ | 1.01 |   | $ | — |   | $ | 0.22 |   | $ | 0.31 |   |
| **Balance  Sheet Data (at period end):**                  |       |                                                              |       |   |   |   |   |   |   |   |   |
| Total assets                                              |       | $                                                                 | 792,750    |   | $ | 178,399 |   | $ | 161,709 |   | $ | 159,521 |   | $ | 152,258 |   |
| Property, plant  and equipment, net                       |       | 532,320                                                           |       | 119,683 |   | 117,032 |   | 116,888 |   | 109,158 |   |
| Payables to  affiliates                                   |       | 189                                                               |       | 127 |   | 1,371 |   | 932 |   | 1,090 |   |
| Long-term  debt                                           |       | 398,000                                                           |       | 57,000 |   | 57,898 |   | 68,740 |   | 65,354 |   |
| Redeemable  preferred units                               |       | —                                                            |       | — |   | 60,982 |   | 53,559 |   | 48,327 |   |
| Members’ capital                                     |       | 281,803                                                           |       | 82,356 |   | (662) |   | 6,577 |   | 16,157 |   |

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| **Cash  Flow Data:**                  |   |     |    |    |   |    |   |    |   |    |   |
|---------------------------------------|--------|----------|---------|---------|--------|---------|--------|---------|--------|---------|--------|
| Net cash flow provided  by (used in): |   |     |    |    |   |    |   |    |   |    |   |
| Operating activities                  |   | $        | 280     |    | $      | 17,697  |   | $       | 15,296 |    | $      | 8,865 |   | $ | 13,107 |   |
| Investing activities                  |   | (491,708 | )       | (8,920  | )      | (6,192  | )      | (16,817 | )      | (93,335 | )      |
| Financing activities                  |   | 509,710  |    | (6,369  | )      | (9,633  | )      | (2,591  | )      | 93,938  |   |
| **Other  Financial Data:**            |   |     |    |    |   |    |   |    |   |    |   |
| Segment Gross Margin:                 |   |     |    |    |   |    |   |    |   |    |   |
| Texas Gulf Coast Pipelines            |   | $        | 32,857  |    | $      | 30,076  |   | $       | 27,551 |    | $      | 18,772 |   | $ | 11,529 |   |
| Texas Gulf Coast Processing(3)        |   | 30,191   |    | 21,425  |   | 3,644   |   | 6,599   |   | 5,459   |   |
| Mid-Continent Operations(4)           |   | 40,683   |    | —  |   | —  |   | —  |   | —  |   |
| Corporate                             |   | 360      |    | —  |   | —  |   | —  |   | —  |   |
| Total gross margin                    |   | $        | 104,091 |    | $      | 51,501  |   | $       | 31,195 |    | $      | 25,371 |   | $ | 16,988 |   |
| EBITDA(5)                             |   | $        | 67,865  |    | $      | 29,532  |   | $       | 13,482 |    | $      | 10,258 |   | $ | 9,605 |   |
| Maintenance capital expenditures(6)   |   | $        | 5,394   |    | $      | 1,790   |   | $       | 2,281  |    | $      | 3,781 |   | $ | 1,175 |   |
| Expansion capital  expenditures(7)    |   | 487,578  |    | 7,130   |   | 3,911   |   | 9,323   |   | 56,746  |   |
| Total capital expenditures            |   | $        | 492,972 |    | $      | 8,920   |   | $       | 6,192  |    | $      | 13,104 |   | $ | 57,921 |   |
| **Operating  Data:**                  |   |     |    |    |   |    |   |    |   |    |   |
| Texas Gulf Coast  Pipelines:          |   |     |    |    |   |    |   |    |   |    |   |
| Pipeline throughput(8) (Mcf/d)   |   | 214,774  |    | 220,970 |   | 238,800 |   | 247,613 |   | 228,657 |   |
| Texas Gulf Coast  Processing:         |   |     |    |    |   |    |   |    |   |    |   |
| Plant inlet volumes (Mcf/d)           |   | 530,346  |    | 529,040 |   | 479,127 |   | 571,217 |   | 614,521 |   |
| NGLs produced (Bbls/d)                |   | 13,066   |    | 15,373  |   | 7,280   |   | 12,656  |   | 15,227  |   |
| Mid-Continent  Operations:(4)         |   |     |    |    |   |    |   |    |   |    |   |
| Pipeline throughput (Mcf/d)           |   | 132,011  |    | —  |   | —  |   | —  |   | —  |   |
| Plant inlet volumes (Mcf/d)           |   | 87,977   |    | —  |   | —  |   | —  |   | —  |   |
| NGLs produced  (Bbls/d)               |   | 9,146    |    | —  |   | —  |   | —  |   | —  |   |

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(1)          Our summary financialand operating data as of and for the year ended December 31, 2005 includethe results of our Mid-Continent Operations from August 1, 2005 (the datewe acquired ScissorTail) through December 31, 2005.

(2)          Net income (loss) perunit is based on the weighted average equivalent units outstanding during theperiods presented. For periods prior to our initial public offering, equivalentunits were calculated using the weighted average of pre-initial public offeringcommon units and common special units adjusted by a conversion or exchangefactor. The computation of diluted units outstanding for all periods presentedexcludes incremental units related to warrants previously held by preferredunitholders and employee unit options because these equity securities had ananti-dilutive effect as a result of losses reported by us for these periods. Cashdistributions for 2002 and 2001 have been restated to reflect the conversiondiscussed previously and the cash distributions for 2004 relate to thedistributions paid to the pre-offering unitholders prior to our initial publicoffering and are based on equivalent units.

(3)          We initiated processingupon acquisition of our Houston Central Processing Plant in August 2001.

(4)          Represents activities related to theScissorTail Acquisition from August 1, 2005 through December 31, 2005.Plant inlet throughput and NGLs produced represents total volumes processed 

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and produced by theMid-Continent Operations segment at all plants, including our own plants andplants owned by third parties. Plant inlet throughput averaged54,893 Mcf/d and NGLs produced averaged 5,500 Bbls/d for plants ownedby the Mid-Continent Operations segment.

(5)          Under the equity methodof accounting, these amounts include our equity in the earnings (loss) ofWebb/Duval Gatherers and Southern Dome, in the amounts of $927, $419 and $(127)for the years ended December 31, 2005, 2004 and 2003, respectively.

(6)          Maintenance capitalexpenditures are capital expenditures employed to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows.

(7)          Expansion capitalexpenditures represent capital expenditures made to expand or increase theefficiency of the existing operating capacity of our assets. Expansion capitalexpenditures include expenditures that facilitate an increase in volumes withinour operations, whether through construction or acquisition. For example,expansion of compression facilities to increase throughput capacity or theacquisition of additional pipelines is considered expansion capitalexpenditures. Expenditures that reduce our operating costs will be consideredexpansion capital expenditures only if the reduction in operating expensesexceeds cost reductions typically resulting from routine maintenance. Costs forrepairs and minor renewals to maintain facilities in operating condition, andwhich do not extend the useful life of existing assets, are consideredoperations and maintenance expenses (and not expansion capital expenditures)and are expensed as incurred.

(8)          Excludes volumesassociated with our interest in Webb/Duval Gatherers, which we acquired in November 2001and February 2002. With respect to assets acquired mid-year, our operatingdata represents daily volumes for the portion of the year we owned the asset.

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Thefollowing table presents a reconciliation of the non-GAAP financial measures of(1) total gross margin (which consists of the sum of individual segmentgross margins) to operating income and (2) EBITDA to the GAAP financialmeasures of net income (loss) and cash flows from operating activities on ahistorical basis for each of the periods indicated. For a detailed discussionof how we use these non-GAAP financial measures, please read Item 7 “Management’s Discussion andAnalysis of Financial Condition and Results of Operation—How We EvaluateOur Operations—Segment Gross Margin and—EBITDA.”

| ** **                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                         | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| Reconciliation of  total gross margin to operating income:         |       |                                       |       |   |   |   |   |   |   |   |   |
| Operating income                                                   |       | $                                          | 50,173     |   | $ | 22,160 |   | $ | 7,348 |   | $ | 4,618 |   | $ | 6,096 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Operations and maintenance expenses                                |       | 18,459                                     |       | 12,486 |   | 10,854 |   | 9,562 |   | 4,960 |   |
| Depreciation and amortization                                      |       | 17,052                                     |       | 7,287 |   | 6,091 |   | 5,539 |   | 3,326 |   |
| General and administrative expenses                                |       | 18,156                                     |       | 9,217 |   | 5,849 |   | 4,177 |   | 2,171 |   |
| Taxes other than income                                            |       | 1,178                                      |       | 770 |   | 926 |   | 891 |   | 435 |   |
| Equity in (earnings) loss of unconsolidated  affiliates            |       | (927                                       | )          | (419 | ) | 127 |   | 584 |   | — |   |
| Total gross  margin                                                |       | $                                          | 104,091    |   | $ | 51,501 |   | $ | 31,195 |   | $ | 25,371 |   | $ | 16,988 |   |
| Reconciliation of EBITDA to net income (loss):                     |       |                                       |       |   |   |   |   |   |   |   |   |
| Net income (loss)                                                  |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) | $ | (1,641 | ) | $ | 4,052 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Depreciation and amortization                                      |       | 17,052                                     |       | 7,287 |   | 6,091 |   | 5,539 |   | 3,326 |   |
| Interest expense                                                   |       | 20,461                                     |       | 23,160 |   | 12,108 |   | 6,360 |   | 2,227 |   |
| EBITDA                                                             |       | $                                          | 67,865     |   | $ | 29,532 |   | $ | 13,482 |   | $ | 10,258 |   | $ | 9,605 |   |
| Reconciliation of EBITDA to cash flows from  operating activities: |       |                                       |       |   |   |   |   |   |   |   |   |
| Cash flow from operating activities                                |       | $                                          | 280        |   | $ | 17,697 |   | $ | 15,296 |   | $ | 8,865 |   | $ | 13,107 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Cash paid for interest and other financing costs              |       | 14,738                                     |       | 4,029 |   | 3,033 |   | 2,543 |   | 946 |   |
| Equity in earnings (loss) of unconsolidated  affiliates            |       | 927                                        |       | 419 |   | (127 | ) | (584 | ) | — |   |
| Risk management assets                                             |       | 42,635                                     |       | — |   | — |   | — |   | — |   |
| Increase (decrease) in working capital                             |       | 9,285                                      |       | 7,387 |   | (4,720 | ) | (566 | ) | (4,448 | ) |
| EBITDA                                                             |       | $                                          | 67,865     |   | $ | 29,532 |   | $ | 13,482 |   | $ | 10,258 |   | $ | 9,605 |   |

 

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**Item 7.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operation

*You should read the following discussion of ourfinancial condition and results of operation in conjunction with the historicalconsolidated financial statements and notes thereto included elsewhere in thisAnnual Report. For more detailed information regarding the basis ofpresentation for the following information, you should read the notes to thehistorical Consolidated Financial Statements included in Item 8 of thisAnnual Report. In addition,you should review “Forward-Looking Statements”contained in this Item 7 of this Annual Report and “Risk Factors”contained in Item 1A of this Annual Report for information regardingforward-looking statements made in this discussion and certain risks inherentin our business. Other risks involved in our business are discussed underItem 7A, “Quantitative and Qualitative Disclosures about Market Risk.”*

**Overview**

We are a Delaware limitedliability company formed in 2001 to acquire entities operating under theCopano name since 1992 and to serve as aholding company for our operating subsidiaries. On November 15,2004, we completed our initial public offering of 5,750,000 common units at aprice of $20.00 per unit, inclusive of 750,000 common units which were issuedas a result of the underwriters’ exercise of their over-allotment option. Netproceeds from the sale of the units totaled $106.9 million.

On August 1, 2005, we acquired all the membershipinterests in Tulsa-based ScissorTail for $499.1 million in cash. ScissorTail’sassets are located in central and eastern Oklahoma and primarily consist ofapproximately 3,330 miles of gathering pipelines and three processing plantswith current processing capacity of approximately 100 MMcf/d. In connection with the ScissorTailAcquisition, we, through ScissorTail, now operate and hold a majority interestin Southern Dome in partnership with the prior ScissorTail ownership group. SouthernDome was formed to engage in the midstream natural gas gathering and processingbusiness and related operations in Oklahoma County, Oklahoma.

We manage ourbusiness and analyze and report our results of operations on a segment basis. Priorto the ScissorTail Acquisition, we divided our operations into two businesssegments:  Copano Pipelines, whichperforms our natural gas gathering and transmission and related operations inTexas, and Copano Processing, which performs our natural gas processing,treating, conditioning and related NGL transportation operations in Texas. Followingthe ScissorTail Acquisition, our operations are divided into four businesssegments, Texas Gulf Coast Pipelines, Texas Gulf Coast Processing,Mid-Continent Operations and Corporate.

·       *Texas Gulf Coast Pipelines*owns networksof natural gas gathering and intrastate pipelines in the Texas Gulf Coastregion and is engaged in the gathering and intrastate transmission of naturalgas in areas we sometimes refer to as the South Texas, Coastal Waters, CentralGulf Coast and Upper Gulf Coast regions. Within this segment, we also providecertain related services including compression, dehydration and marketing ofnatural gas. For the year ended December 31, 2005 and 2004, this segmentgenerated approximately 32% and 58%, respectively, of our total gross margin.

·       *Texas Gulf Coast Processing*is engaged innatural gas processing, conditioning and treating and NGL fractionation andtransportation through our Houston Central Processing Plant and Sheridan NGLPipeline. Our natural gas processing plant is the second largest in the TexasGulf Coast region and the third largest in Texas in terms of throughputcapacity. The plant is located approximately 100 miles southwest of Houston,Texas. For the year ended December 31, 2005 and 2004, this segment generatedapproximately 29% and 42%, respectively, of our total gross margin.

·       *Mid-Continent Operations*is a provider ofnatural gas midstream services in central and eastern Oklahoma, includingnatural gas gathering and related compression and dehydration services andnatural gas processing. For the year ended December 31, 2005 and 2004,this segment generated 

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approximately 39% and 0%,respectively, of our total gross margin which included Mid-Continent Operationsfrom August 1, 2005 through December 31, 2005.

·       *Corporate* engages in risk management and other corporateactivities. For the years ended December 31, 2005 and 2004, this segmentgenerated a negligible amount of our total gross margin.

Total gross margin is a non-GAAP financial measure. Fora reconciliation of total gross margin to its most directly comparable GAAPmeasure, please read Item 6 “Selected Financial Data.”

Our segment gross margins are determined primarily byfour interrelated variables: (1) the volume of natural gas gathered ortransported through our pipelines, (2) the volume of natural gasprocessed, conditioned or treated at our Houston Central Processing Plant, thethree processing plants operated by our Mid-Continent Operations segment andthird-party processing plants, (3) the level and relationship of naturalgas and NGL prices and (4) our current contract portfolio. Because ourprofitability is a function of the difference between the revenues we receivefrom our operations, including revenues from the products we sell, and the costsassociated with conducting our operations, including the costs of products wepurchase, increases or decreases in our revenues alone are not necessarilyindicative of increases or decreases in our profitability. To a large extent,our contract portfolio and the pricing environment for natural gas and NGLswill dictate increases or decreases in our profitability. For a discussion ofthe types of contracts we utilize and management’s analysis of our recentresults of operations, please read “—Our Contracts” and “—Our Results ofOperation.”  Our profitability is alsodependent upon prices and market demand for natural gas and NGLs, whichfluctuate with changes in market and economic conditions and other factors.

The margins we realizefrom a significant portion of the natural gas gathered or transported by TexasGulf Coast Pipelines decrease during periods of low natural gas prices becauseour unit margins on such natural gas volumes are based on a percentage of theindex price. The profitability of Texas Gulf Coast Processing is dependent uponthe relationship between natural gas and NGL prices. When natural gas pricesare low relative to NGL prices, it is more profitable for Texas Gulf CoastProcessing to process natural gas than to condition it. Conversely, whennatural gas prices are high relative to NGL prices, processing is lessprofitable or unprofitable. During such periods, our Houston Central ProcessingPlant has the flexibility to condition natural gas rather than fully process it.Conditioning natural gas, however, is less profitable than processing duringperiods when the value of recovered NGLs exceeds the value of natural gasrequired for plant fuel and to replace the reduced Btus that result fromprocessing the natural gas. Mid-Continent Operations’ margins are, on thewhole, positively correlated with NGL prices and are not significantly impactedby changes in natural gas prices.

***How We Evaluate Our Operations***

We believe that investors benefit from having accessto the same financial measures that our management uses in evaluating ourperformance. Our management uses a variety of financial and operationalmeasurements to analyze our performance. These measurements include thefollowing: (1) throughput volumes; (2) segment gross margin; (3) operationsand maintenance expenses; (4) general and administrative expenses; (5) EBITDAand (6) distributable cash flow.

*ThroughputVolumes.**  *Throughputvolumes associated with our business are an important part of our operationalanalysis. We continually evaluate volumes on our pipelines to ensure that wehave adequate throughput to meet our financial objectives. It is important thatwe continually add new volumes to our gathering systems to offset or exceed thenormal decline of existing volumes that are attached to those systems. Ourperformance at our processing plants is significantly influenced by both thevolume of natural gas coming into the plant and the NGL content of the naturalgas. In addition, we monitor fuel consumption because it has a significantimpact on the gross margin realized from our processing or 

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conditioning operations. Althoughwe monitor fuel costs associated with our pipeline operations, these costs arefrequently passed on to our producers.

*SegmentGross Margin.**  *Wedefine segment gross margin as our segment revenue minus cost of sales. Cost ofsales includes the following costs and expenses: cost of natural gas and NGLspurchased by us from third parties, cost of natural gas and NGLs purchased byus from affiliates, costs we pay third parties to transport our volumes andcosts we pay our affiliates to transport our volumes. We view segment grossmargin as an important performance measure of the core profitability of ouroperations. The segment gross margin data reflect the financial impact on ourcompany of our contract portfolio. With respect to our Texas Gulf CoastPipelines segment, our management analyzes segment gross margin per unit ofvolumes gathered or transported. With respect to our Texas Gulf CoastProcessing segment, our management also analyzes segment gross margin per unitof natural gas processed or conditioned and the segment gross margin per unitof NGLs recovered. With respect to our Mid-Continent Operations segment, ourmanagement analyzes segment gross margin per unit on volumes gathered ortransported, per unit of natural gas processed and per unit of NGLs recovered. Oursegment gross margin is reviewed monthly for consistency and trend analysis.

To isolate and consistently track changes in commodityprice relationships and their impact on our Texas Gulf Coast Processing segment’sresults, we calculate a hypothetical “standardized” processing margin. Thisprocessing margin is based on a fixed set of assumptions, with respect toliquids composition and fuel consumption per recovered gallon, which we believeis generally reflective of our business. Because these assumptions are heldstable over time, changes in underlying natural gas and NGL prices drivechanges in the standardized processing margin. Our financial results are notderived from this standardized processing margin and the standardized margin isnot derived from our financial results. However, we believe this calculation isrepresentative of the current operating commodity price environment of ourTexas Gulf Coast Processing operations and we use this calculation to trackcommodity price relationships. Our results of operations may not necessarilycorrelate to the changes in our standardized processing margin because of theimpact of factors other than commodity prices such as volumes, changes in NGLcomposition, recovery rates and variable contract terms. Our standardizedprocessing margins averaged $0.0899, $0.105 and $0.002 per gallon during theyears ended December 31, 2005, 2004 and 2003, respectively. The averagestandardized processing margin for the period from 1989 through December 31,2005 is $0.0907 per gallon.

*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses are costsassociated with the operations of a specific asset. Direct labor, insurance, advalorem taxes, repair and maintenance, utilities and contract services comprisethe most significant portion of operations and maintenance expenses. Theseexpenses remain relatively stable across broad volume ranges and fluctuateslightly depending on the activities performed during a specific period. Aportion of our operations and maintenance expenses are incurred through CopanoOperations, an affiliate of our company and controlled by Mr. John R.Eckel, Jr., the Chairman of our Board of Directors and our Chief ExecutiveOfficer. Under the terms of our arrangement with Copano Operations, we haveagreed to reimburse it, at cost, for the operations and maintenance expenses itincurs on our behalf. Effective January 1, 2005 and pursuant to ourgeneral and administrative services agreement with Copano Operations, CopanoOperations transferred responsibility to us for a significant portion of theservices, including certain operating and maintenance services, that it hadpreviously provided to us.

*Generaland Administrative Expenses.**  *Our general and administrative expenses include thecost of employee and officer compensation and related benefits, office leaseand expenses, professional fees, information technology expenses, as well asother expenses not directly associated with our field operations. Substantiallyall of our general and administrative expenses were incurred through CopanoOperations, an affiliate of our company, through December 31, 2004. EffectiveJanuary 1, 2005 and pursuant to our general and administrative servicesagreement with Copano Operations, Copano 

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Operations transferredresponsibility to us for a significant portion of the services, includingcertain general and administrative services, that it had previously provided tous.

Pursuantto our limited liability company agreement, our investors existing prior to ourinitial public offering, or our pre-offering investors, agreed to reimburse usfor our general and administrative expenses in excess of stated levels (subjectto certain limitations discussed below) for a period of three years beginningon January 1, 2005. Specifically, to the extent our general andadministrative expenses exceed the following levels, the portion of the generaland administrative expenses ultimately funded by us (subject to certainadjustments and exclusions) will be limited, or capped, as indicated:

| **Year** | ** ** | ** **                 | ** ** | **General and Administrative Expense  Limitations** |
|----------|------------|----------------------------|------------|-----------------------------------------------------|
| 1        |       | $1.50 million per  quarter |
| 2        |       | $1.65 million per  quarter |
| 3        |       | $1.80 million per quarter  |

 

During this three-year period, the quarterlylimitation on general and administrative expenses will be increased by 10% ofthe amount by which EBITDA (as defined below) for any quarter exceeds $5.4million. Additionally, the cap may be extended beyond its initial three-yearterm at the same or a higher level by the affirmative vote of at least 95% ofthe common and subordinated units held by our pre-offering investors or theirassignees, voting together as a single class. We can provide no assurance as toany such extension, as such determination will be made in the sole discretionof our pre-offering investors. This cap on general and administrative expensesexcludes non-cash expenses as well as expenses we may incur in connection withpotential acquisitions and capital improvements.

Immediately prior to completion of the initial publicoffering, we distributed to our pre-offering investors $4 million (the “OriginalEscrow Amount”). Our pre-offering investors deposited these funds in escrowaccounts to be used for the purpose of satisfying their respective general andadministrative expense reimbursement obligation. Pursuant to our limitedliability company agreement, upon exhaustion of the Original Escrow Amount, anyfurther reimbursement obligation is limited solely to the amount of thedistributions attributable to the 5,557,378 common and subordinated units ownedby the pre-offering investors immediately prior to our initial public offering(the “Pre-Offering Units”). In order to facilitate the payment of any furtherreimbursement obligation, our limited liability company agreement provides thatwe may deposit any distributions that are required to cover the obligation andare otherwise payable to our pre-offering investors, directly in the pre-offeringinvestors’ escrow accounts. Also, to the extent that any of our pre-offeringinvestors sell Pre-Offering Units, the buyer must assume the relatedreimbursement obligations or the selling pre-offering investor must depositcertain funds in its escrow account to secure the payment of any futurereimbursement obligation with respect to the units transferred. During 2005,pre-offering investors made capital contributions to us in the aggregate amountof $4.1 million as reimbursement of excess general and administrativeexpenses for the first three quarters of 2005. The pre-offering investors made$4.0 million of these capital contributions from the Original EscrowAmount and the remaining $0.1 million was made from distributions on ourunits received by these pre-offering investors. In February 2006,pre-offering investors made capital contributions to us in the aggregate amountof $1.4 million as reimbursement of excess general and administrativeexpenses for the fourth quarter of 2005. This contribution was funded fromdistributions on our units received by these pre-offering investors as well asfrom certain funds previously deposited in escrow in connection with unittransfers. We believe that our ability to deposit distributions required tosatisfy pre-offering investors’ reimbursement obligations directly in escrowtogether with the escrow requirements relating to the sale of any Pre-OfferingUnits provides us with additional assurance that our pre-offering investorswill be able to satisfy any future reimbursement obligations with respect tothe Pre-Offering Units.

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*EBITDA.**  *We define EBITDA as net income(loss) plus interest expense, provision for income taxes and depreciation andamortization expense. EBITDA is used as a supplemental financial measure by ourmanagement and by external users of our financial statements such as investors,commercial banks, research analysts and others, to assess:

·       thefinancial performance of our assets without regard to financing methods,capital structure or historical cost basis;

·       theability of our assets to generate cash sufficient to pay interest costs andsupport our indebtedness;

·       ouroperating performance and return on capital as compared to those of othercompanies in the midstream energy sector, without regard to financing orcapital structure; and

·       theviability of acquisitions and capital expenditure projects and the overallrates of return on alternative investment opportunities.

EBITDA is also a financial measurement that, withcertain negotiated adjustments, is reported to our lenders and is used tocompute our financial covenants under our credit facilities. EBITDA should notbe considered an alternative to net income, operating income, cash flows fromoperating activities or any other measure of financial performance presented inaccordance with GAAP.

*Distributable Cash Flow:**  *We define distributable cash flowas net income or loss plus: (1) depreciation and amortization expense; (2) cashdistributions received from investments in unconsolidated affiliates lessequity in the earnings of such unconsolidated affiliates; (3) reimbursementsby our pre-offering investors of certain general and administrative expenses inexcess of the “G&A Cap” defined in our limited liability company agreement;(4) the subtraction of maintenance capital expenditures; and (5) theaddition of losses or subtraction of gains relating to other miscellaneousnon-cash amounts affecting net income for the period. Maintenance capitalexpenditures are capital expenditures employed to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows. Distributablecash flow is a significant performance metric used by senior management tocompare basic cash flows generated by us (prior to the establishment of anyretained cash reserves by our Board of Directors) to the cash distributions weexpect to pay our unitholders. Using this metric, management can quicklycompute the coverage ratio of estimated cash flows to planned cashdistributions. Distributable cash flow is also an important non-GAAP financialmeasure for our unitholders since it serves as an indicator of our success inproviding a cash return on investment. Specifically, this financial measureindicates to investors whether or not we are generating cash flow at a levelthat can sustain or support an increase in our quarterly distribution rates. Distributablecash flow is also a quantitative standard used throughout the investmentcommunity with respect to publicly-traded partnerships and limited liabilitycompanies because the value of a unit of such an entity is generally determinedby the unit’s yield (which in turn is based on the amount of cash distributionsthe entity can pay to a unitholder).

***How We Manage Our Operations***

Our management team uses a variety of tools to manageour business. These tools include: (1) our economic models; (2) flowand transaction monitoring systems; (3) producer activity evaluation andreporting; and (4) imbalance monitoring and control.

*OurEconomic Models.**  *Weutilize our economic models to determine (i) whether we should process orcondition natural gas at our Houston Central Processing Plant, (ii) whetherwe should elect payment under certain Mid-Continent Operations’ “switch”contracts using a percentage-of-index basis or a 

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percentage-of-proceedsbasis and (iii) whether we should reduce the ethane extracted from certainnatural gas processed at our Texas Gulf Coast Processing and Mid-ContinentOperations plants.

*Flowand Transaction Monitoring Systems.**  *We utilize automated systems thattrack commercial activity on each of our pipelines and monitor the flow ofnatural gas on our pipelines. For example, in our Texas Gulf Coast Pipelinesoperations we designed and implemented software that tracks each of our naturalgas transactions, which allows us to continuously track volumes, pricing,imbalances and estimated revenues from our pipeline assets. Additionally, weutilize an automated Supervisory Control and Data Acquisition (SCADA) system,which assists management in monitoring and operating our Texas Gulf Coastpipeline systems. The SCADA system allows us to monitor our assets at remotelocations and respond to changes in pipeline operating conditions from ourHouston office. For our Mid-Continent Operations, we electronically monitorpipeline volumes and operating conditions at certain key points along ourpipeline systems.

*ProducerActivity Evaluation and Reporting.**  *We monitor the producer drillingand completion activity in our areas of operation to identify anticipatedchanges in production and potential new well attachment opportunities. Thecontinued attachment of natural gas production to our pipeline systems iscritical to our business and directly impacts our financial performance. Usinga third-party electronic reporting system, we receive daily reports of newdrilling permits and completion reports filed with the state regulatory agencythat governs these activities. Additionally, our field personnel report thelocations of new wells in their respective areas and anticipated changes inproduction volumes to supply representatives and operating personnel. Theseprocesses enhance our awareness of new well activity in our operating areas andallow us to be responsive to producers in connecting new volumes of natural gasto our pipelines.

*Imbalance Monitoring andControl.**  *Wecontinually monitor volumes received and volumes delivered on behalf of thirdparties to ensure we remain within acceptable imbalance limits during thecalendar month. We seek to reduce imbalances because of the inherent commodityprice risk that results when receipts and deliveries of natural gas are notbalanced concurrently. We have implemented “cash-out” provisions in many of ourtransportation agreements to reduce this commodity price risk. Cash-outprovisions require that any imbalance that exists between a third party and usat the end of a calendar month is settled in cash based upon a pre-determinedpricing formula. This provision ensures that imbalances under such contractsare not carried forward from month-to-month and revalued at higher or lowerprices.

**Our Contracts**

We seek to executecontracts with producers and shippers that provide us with positive grossmargin in all natural gas and NGL pricing environments. Actual contract terms,however, are based upon a variety of factors including gas quality, pressuresof natural gas production relative to downstream transporter pressurerequirements, the competitive environment at the time the contract is executedand customer requirements. Our contract mix and, accordingly, our exposure tonatural gas and NGL prices, may change as a result of changes in producerpreferences, our expansion in regions where some types of contracts are morecommon and other market factors.

**Texas Gulf CoastPipelines Contracts**

Our Texas Gulf Coast Pipelines segment purchasesnatural gas for transportation and resale and also transports and providesother services for natural gas that it does not purchase on a fee-for-servicebasis. For the year ended December 31, 2005, we purchased 66% of thenatural gas volumes delivered to our pipelines and transported 34% on afee-for-service basis. These volumes exclude volumes associated with WebbDuval, substantially all of which are transported on a fee-for-service basis.

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*NaturalGas Purchases.**  *Generally,we purchase natural gas attached to our pipeline systems underdiscount-to-index arrangements. Under these arrangements, we generally purchasenatural gas at either (1) a percentage discount to an index price, (2) anindex price less a fixed amount or (3) a percentage discount to an indexprice less a fixed amount. We then gather, deliver and resell the natural gasunder arrangements described below. For the year ended December 31, 2005,volumes related to discount-to-index purchase arrangements accounted for 96% oftotal purchased volumes. The gross margins we realize under the arrangementsdescribed in clauses (1) and (3) above decrease in periods of lownatural gas prices and increase during months of high natural gas pricesbecause these gross margins are based on a percentage of the index price. Inmany cases, our contracts for natural gas purchases allow us to chargeproducers fees for treating, compression, dehydration or services other thanprocessing and conditioning.

We also purchase natural gas under a limited number ofintra-month, fixed-price arrangements used for balancing our portfolio for themonth. Transactions under these arrangements are executed to supportintra-month changes in operating conditions, including customer requirements,and not for purposes of speculation. For the year ended December 31, 2005,volumes related to such fixed-price arrangements accounted for 4% of totalpurchased volumes.

*Fee-For-ServiceTransport.**  *Wegenerally transport natural gas on our pipeline systems under fixed feearrangements pursuant to which our transportation fee income represents anagreed rate per unit of throughput. The revenue we earn from these arrangementsis directly related to the volume of natural gas that flows through our systemsand is not directly dependent on commodity prices. To the extent a sustaineddecline in commodity prices results in a decline in volumes, however, ourrevenues from these arrangements would be reduced. For the year ended December 31,2005, volumes related to fixed-fee arrangements accounted for 74% of totalnatural gas volumes that we transport on behalf of third-party shippers.

We also derive some transportation fee income basedupon percentage-of-index fee arrangements. Under this type of arrangement, thefee we receive for gathering or transporting the natural gas is based upon apercentage of an index price. The fee we realize under this type of arrangementdecreases in periods of low natural gas prices and increases during periods ofhigh natural gas prices. For the year ended December 31, 2005, volumesrelated to percentage-of-index fee arrangements accounted for 2% of totaltransported volumes. For the year ended December 31, 2005, volumes relatedto a combination of fixed-fee and percentage-of-index fee arrangementsaccounted for 24% of total transported volumes. In many cases, our contractsfor natural gas transportation allow us to charge shippers fees for treating,compression, dehydration or services other than processing and conditioning.

*NaturalGas Sales.**  *Wesell natural gas to other natural gas pipelines, marketing affiliates ofintegrated oil companies or other midstream companies, utilities, powerproducers and end-users. We sell natural gas under index-related pricing termswith the exception of a limited number of intra-month fixed-price salesarrangements used for balancing our portfolio for the month. Transactions underthese fixed-price arrangements are executed to support intra-month changes inoperating conditions, including customer requirements, and not for purposes ofspeculation.

*Processing andConditioning Services.**  *Withrespect to natural gas requiring processing and conditioning services, ourTexas Gulf Coast Pipelines segment contracts with our Texas Gulf CoastProcessing segment to provide such services on the terms described below.

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**Texas Gulf CoastProcessing Contracts**

With respect toservices performed by our Texas Gulf Coast Processing operations, we contractunder the following types of arrangements:

·       *Keep-Whole with Conditioning Fee Arrangements.  *Underkeep-whole with conditioning fee arrangements, we receive natural gas fromproducers and third-party transporters, process or condition the natural gasand sell the resulting NGLs to third parties at market prices. Under thesetypes of arrangements, we also charge producers and third-party transporters aconditioning fee, at all times or in certain circumstances depending upon theterms of the particular contract. These fees provide us additional revenue andcompensate us for the services required to redeliver natural gas that meetsdownstream pipeline quality specifications. The extraction of NGLs from thenatural gas during processing or conditioning reduces the Btus of the naturalgas. To replace these Btus, we must purchase natural gas at market prices forreturn to producers and transporters. Accordingly, under these arrangements,our revenues and gross margins increase as the price of NGLs increase relativeto the price of natural gas, and our revenues and gross margins decrease as theprice of natural gas increases relative to the price of NGLs. In the lattercase, we are generally able to reduce our commodity price exposure byconditioning rather than processing the natural gas, as described below. Forthe year ended December 31, 2005, volumes at our Houston CentralProcessing Plant related to this type of fee arrangement accounted for 86% oftotal plant volumes.

·       *Keep-Whole Without Conditioning Fee Arrangements.  *Underkeep-whole without conditioning fee arrangements, we receive natural gas fromthe producer or third-party transporter, process the natural gas and sell theresulting NGLs to third parties at market prices. Like the arrangementdescribed above, under these contracts we are required to replace the Btusreduced during processing or conditioning. These contracts are subject to allof the considerations described in “Keep-Whole With Conditioning FeeArrangements” above, except that we do not charge the producer or transporter aconditioning fee. It is generally not our policy to enter into new keep-wholecontracts without conditioning fee arrangements. For the year ended December 31,2005, volumes at our Houston Central Processing Plant related to this type offee arrangement accounted for 12% of total plant volumes. Our Texas Gulf CoastPipelines segment earned gross margins with respect to these volumes pursuantto other provisions of the applicable contract.

·       *Percentage-of-Proceeds Arrangements.  *Underpercentage-of-proceeds arrangements, we generally receive and process naturalgas on behalf of producers, sell or redeliver the resulting residue gas andsell the NGL volumes at index-related prices. We remit to producers an agreedupon index-related price for the natural gas, if not redelivered, and an agreedupon percentage of the NGL proceeds. Under these types of arrangements, ourrevenues and gross margins increase as NGL prices increase, and our revenuesand gross margins decrease as NGL prices decrease. For the year ended December 31,2005, volumes at our Houston Central Processing Plant related to this type offee arrangement accounted for 2% of total plant volumes.

·       *Fixed Fee, or Tolling, Arrangements.  *Underfixed fee arrangements, producers pay us a fixed fee to process their naturalgas. These types of arrangements require us to pay the producer for the valueof NGLs recovered and to redeliver the residue gas in exchange for a fixed fee.For the year ended December 31, 2005, volumes at our Houston CentralProcessing Plant related to this type of fee arrangement accounted for lessthan 1% of total plant volumes.

We also provide processing and conditioning servicesunder contracts that contain a combination of the arrangements described above.Additionally, we may share a fixed or variable portion of our processingmargins with the producer or third-party transporter during periods where suchmargins are in excess of an agreed-upon amount.

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All of our processing agreements allow us todetermine, in our sole discretion, whether we process or condition natural gas.We determine whether to process or condition the natural gas based upon theprice of natural gas and various NGL products. When NGL extraction isuneconomic, NGLs are left in the natural gas stream to the maximum extentallowed by pipeline quality specifications, thus reducing the amount of fuelconsumed by the processing plant and the loss in Btus resulting from theextraction of the NGLs. When we elect to condition natural gas, typically ournatural gas fuel consumption volumes are reduced by approximately 79% and theBtu reduction associated with the extraction of NGLs is reduced byapproximately 94% while our average barrels of NGLs extracted from natural gasis reduced by approximately 96%. For a detailed discussion of our processingand conditioning capabilities, please read Item 1 “Business—Our Operations—TexasGulf Coast Processing Segment” of this Annual Report.

*NGLProduct Sales.**  *Weuse our Sheridan NGL Pipeline to transport NGLs to an interconnect withEnterprise Seminole Pipeline where we sell the NGLs at market prices. At thetailgate of the plant, we deliver and sell stabilized condensate to TEPPCObased on an index-related price.

*Our CommercialRelationship with Kinder Morgan Texas Pipeline.**  *For the year ended December 31,2005, approximately 83% of the natural gas volumes processed or conditioned atour Houston Central Processing Plant was delivered to the plant through theKMTP Laredo-to-Katy pipeline while the remaining 17% was delivered directly tothe plant from our gathering systems. Of the volumes delivered to the plantfrom the KMTP Laredo-to-Katy pipeline, approximately 25% were delivered fromgathering systems controlled by us, while 75% were delivered by KMTP fromsources other than our gathering systems. We refer to the natural gas deliveredinto the KMTP Laredo-to-Katy pipeline from sources other than our gatheringsystems as “KMTP Gas.”  Of the totalvolume of NGLs extracted at the plant during this period, 39% originated fromKMTP Gas, while 61% was attributable to gathering systems controlled by us,including our gathering systems connected directly to the plant. Under ourcontractual arrangement related to KMTP Gas, we receive natural gas at ourplant, process or condition the natural gas and sell the NGLs to third partiesat market prices. Because the extraction of NGLs from the natural gas streamduring processing or conditioning reduces the Btus of the natural gas, ourarrangement with KMTP requires us to purchase natural gas at market prices toreplace the loss in Btus. Pursuant to an amendment to this contract with KMTP,effective January 1, 2004, we pay a fee to KMTP based on the NGL contentof the KMTP Gas only during periods of favorable processing margins. Inaddition, the amendment provides that during periods of unfavorable processingmargins, KMTP pays us a fixed fee plus an additional payment based on the indexprice of natural gas.

**Mid-ContinentOperations Contracts**

*NaturalGas Supply and Transportation.**  *We contract for supplies of naturalgas from producers in our Mid-Continent region under several types ofarrangements. Processing services, where applicable, are included in thepurchase or transportation contract arrangement. Typically, the primary term ofeach contract varies significantly, ranging from one month to the life of thededicated production. The specific terms of each natural gas supply contractare based upon a variety of factors including gas quality, pressure of naturalgas production relative to downstream transporter pressure requirements, thecompetitive environment at the time the contract is executed and customerrequirements. These contracts may be structured as a percentage-of-proceeds,percentage-of-index, or fixed fee arrangements. For the period from August 1,through December 31, 2005, calculated as a percentage of total volumes,51% of our Mid-Continent volumes were under percentage-of-proceeds contracts,32% were under percentage-of-index contracts and 17% were under fixed fee contracts.

*Percentage-of-ProceedsArrangements.**  *Underpercentage-of-proceeds arrangements, our Mid-Continent Operations segmentgenerally receives and processes natural gas on behalf of producers and sellsthe residue gas and NGL volumes at index-related prices. We remit to producersan agreed upon percentage of the residue gas and NGL proceeds. Under thesetypes of arrangements, our revenues and 

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gross margins increase asnatural gas and NGL prices increase, and our revenues and gross marginsdecrease as natural gas and NGL prices decrease.

*Percentage-of-IndexArrangements.**  *Ourpercentage-of-index contracts are divided into two subcategories—simplepercentage-of-index contracts comprised 17% of our Mid-Continent Operations’volumes for the period from August 1, through December 31, 2005,while percentage-of-index with percentage-of-proceeds “switch” contractscomprised 15% of our Mid-Continent Operations’ volumes for the period from August 1,through December 31, 2005. Under a percentage-of-index contract, wepurchase and resell natural gas at an index-related price, deriving our grossmargins from the difference. Under a percentage-of-index with apercentage-of-proceeds switch arrangement, we pay producers on either apercentage-of-proceeds or percentage-of-index basis, determined under thesecontracts on the basis most favorable to us.

*FixedFee Arrangements.**  *Undersubstantially all fixed fee arrangements, producers pay us a fixed fee togather their natural gas.

*Natural Gas Sales and NGLSales.**  *Wesell natural gas in the Mid-Continent region under index-related pricing termsto marketing affiliates of integrated companies or other midstream companies,power producers and end-users. We sell natural gas under index-related pricingterms. Oneok Energy Services and Enogex are the largest purchasers of ournatural gas. With respect to sales of NGLs in the Mid-Continent region, we sellthe majority of our NGLs to Oneok Hydrocarbon Products Inc. or Enogex. All NGLsare sold under index-related pricing arrangements.

**Our Growth Strategy**

Our growth strategy contemplates complementary acquisitionsof midstream assets in our operating areas as well as capital expenditures toenhance our ability to increase cash flows from our existing assets. We intendto pursue acquisitions and capital expenditure projects that we believe willallow us to capitalize on our existing infrastructure, personnel andrelationships with producers and customers to provide midstream services. Wealso evaluate acquisitions in new geographic areas, including other areas ofTexas and Oklahoma and in New Mexico and the Rocky Mountain region, to theextent they present growth opportunities similar to those we are pursuing inour existing areas of operations. To successfully execute our growth strategy,we will require access to capital on competitive terms. We believe that we willhave a lower cost of equity capital than many of our competitors that aremaster limited partnerships, or MLPs, because, unlike in a traditional MLPstructure, neither our management nor any other party holds incentive distributionrights that entitle them to increasing percentages of cash distributions ashigher per  unit levels of cash distributions are received. We intend tofinance future acquisitions primarily through the issuance of debt andequity. For a more detailed discussion of our capital resources, please read “—Liquidityand Capital Resources.”

*AcquisitionAnalysis.**  *Inanalyzing a particular acquisition, we consider the operational, financial andstrategic benefits of the transaction. Our analysis includes location of theassets, strategic fit of the asset in relation to our business strategy,expertise required to manage the asset, capital required to integrate andmaintain the asset, and the competitive environment of the area where theassets are located. From a financial perspective, we analyze the rate of returnthe assets will generate under various case scenarios, comparative marketparameters and the additive earnings and cash flow capabilities of the assets.

*Capital ExpenditureAnalysis.**  *Wemake capital expenditures either to maintain our assets or the supply ofnatural gas volumes to our assets or for expansion projects to increase ourgross margin. Maintenance capital expenditures are capital expendituresemployed to replace partially or fully depreciated assets to maintain theexisting operating capacity of our assets and to extend their useful lives, orother capital expenditures that are incurred in maintaining existing systemvolumes and related cash flows. Expansion capital expenditures representcapital expenditures made to expand or increase the 

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efficiency of theexisting operating capacity of our assets. Expansion capital expendituresinclude expenditures that facilitate an increase in volumes within ouroperations, whether through construction or acquisition. Expenditures thatreduce our operating costs will be considered expansion capital expendituresonly if the reduction in operating expenses exceeds cost reductions typicallyresulting from routine maintenance. Our decisions whether to spend capital onexpansion projects are generally based on anticipated earnings, cash flow andrate of return of the assets.

**Items Impacting Comparability of Our Financial Results**

*Our Acquisitions*

Since our inception in 1992, we have grown through acombination of over 30 acquisitions, including the acquisition of our HoustonCentral Processing Plant and our recent acquisition of ScissorTail, andsignificant expansion and enhancement projects related to our assets. Ourhistorical acquisitions were completed at different dates and with numeroussellers and were accounted for using the purchase method of accounting. Underthe purchase method of accounting, results of operations from such acquisitionsare recorded in the financial statements only from the date of acquisition. Asa result, our historical results of operations for the periods presented maynot be comparable, as they reflect the results of operations of a business thathas grown significantly due to acquisitions.

On August 1, 2005, we acquired ScissorTail for$499.1 million, and now refer to the business and properties of ScissorTail asour Mid-Continent Operations segment. The ScissorTail Acquisition nearlytripled our miles of natural gas gathering pipelines and increased processingcapacity by 100 MMcf/d and is expected to provide significant additionalthroughput volumes and cash flow. Our year ended December 31, 2005 resultsof operation include the results of our Mid-Continent Operations from August 1,2005 (the date we acquired ScissorTail) through December 31, 2005 and theMid-Continent Operations generated approximately 39% of our total gross marginfor the year ended December 31, 2005.

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**Our Results ofOperation**

| ** **                                                | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2005(1)**                                | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                | ** ** | **($ in thousands)**             | ** ** |
| Total gross margin(2)                                     |       | $                                          | 104,091    |   | $ | 51,501 |   | $ | 31,195 |   |
| Operations and maintenance expenses                       |       | 18,459                                     |       | 12,486 |   | 10,854 |   |
| Depreciation and amortization                             |       | 17.052                                     |       | 7,287 |   | 6,091 |   |
| General and administrative expenses                       |       | 18,156                                     |       | 9,217 |   | 5,849 |   |
| Taxes other than income                                   |       | 1,178                                      |       | 770 |   | 926 |   |
| Equity in (earnings) loss from unconsolidated  affiliates |       | (927                                       | )          | (419 | ) | 127 |   |
| Operating income                                          |       | 50,173                                     |       | 22,160 |   | 7,348 |   |
| Interest and other financing costs, net                   |       | (19,821                                    | )          | (23,075 | ) | (12,065 | ) |
| Net income (loss)                                         |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Segment gross  margin:                                    |       |                                       |       |   |   |   |   |
| Texas Gulf Coast Pipelines(3)                             |       | $                                          | 32,857     |   | $ | 30,076 |   | $ | 27,551 |   |
| Texas Gulf Coast Processing                               |       | 30,191                                     |       | 21,425 |   | 3,644 |   |
| Mid-Continent Operations(4)                               |       | 40,683                                     |       | — |   | — |   |
| Corporate                                                 |       | 360                                        |       | — |   | — |   |
| Total gross margin(2)                                     |       | $                                          | 104,091    |   | $ | 51,501 |   | $ | 31,195 |   |
| Segment gross  margin per unit:                           |       |                                       |       |   |   |   |   |
| Texas Gulf Coast  Pipelines:                              |       |                                       |       |   |   |   |   |
| Pipeline throughput ($/MMBtu)(3)                          |       | $                                          | 0.39       |   | $ | 0.35 |   | $ | 0.29 |   |
| Texas Gulf Coast  Processing:                             |       |                                       |       |   |   |   |   |
| Plant inlet throughput ($/MMBtu)(5)                       |       | $                                          | 0.15       |   | 0.10 |   | 0.02 |   |
| NGLs produced ($/Bbl)(5)                                  |       | $                                          | 6.33       |   | 3.81 |   | 1.37 |   |
| Mid-Continent  Operations:(4)                             |       |                                       |       |   |   |   |   |
| Pipeline throughput ($/MMBtu)                             |       | $                                          | 1.68       |   | — |   | — |   |
| Plant inlet throughput ($/MMBtu)                          |       | $                                          | 2.49       |   | — |   | — |   |
| NGLs produced ($/Bbl)                                     |       | $                                          | 29.07      |   | — |   | — |   |
| Volumes:                                                  |       |                                       |       |   |   |   |   |
| Texas Gulf Coast  Pipelines:                              |       |                                       |       |   |   |   |   |
| Pipeline throughput (MMBtu/d)(3)                          |       | 232,280                                    |       | 239,770 |   | 256,556 |   |
| Texas Gulf Coast  Processing:                             |       |                                       |       |   |   |   |   |
| Plant inlet throughput (MMBtu/d)                          |       | 561,085                                    |       | 559,939 |   | 502,057 |   |
| NGLs produced (Bbls/d)                                    |       | 13,066                                     |       | 15,373 |   | 7,280 |   |
| Mid-Continent  Operations:(4)                             |       |                                       |       |   |   |   |   |
| Pipeline throughput (MMBtu/d)                             |       | 158,334                                    |       | — |   | — |   |
| Plant inlet throughput (MMBtu/d)                          |       | 106,877                                    |       | — |   | — |   |
| NGLs produced (Bbl/d)                                     |       | 9,146                                      |       | — |   | — |   |
| Maintenance capital expenditures(6)                       |       | $                                          | 5,394      |   | $ | 1,790 |   | $ | 2,281 |   |
| Expansion capital expenditures(7)                         |       | 487,578                                    |       | 7,130 |   | 3,911 |   |
| Total capital expenditures                                |       | $                                          | 492,972    |   | $ | 8,920 |   | $ | 6,192 |   |
| Operations and  maintenance expenses:                     |       |                                       |       |   |   |   |   |
| Texas Gulf Coast Pipelines                                |       | $                                          | 5,516      |   | $ | 5,813 |   | $ | 5,161 |   |
| Texas Gulf Coast Processing                               |       | 7,026                                      |       | 6,673 |   | 5,693 |   |
| Mid-Continent Operations                                  |       | 5,917                                      |       | — |   | — |   |
| Total operations  and maintenance expenses                |       | $                                          | 18,459     |   | $ | 12,486 |   | $ | 10,854 |   |

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(1)           Oursummary financial and operating data for the year ended December 31, 2005 includethe results of our Mid-Continent Operations from August 1, 2005 (the date weacquired ScissorTail) through December 31, 2005.

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(2)           Totalgross margin is a non-GAAP financial measure. For a reconciliation of totalgross margin to its most directly comparable GAAP measure, please read Item 6 “SelectedFinancial Data” of this Annual Report.

(3)           Excludes results and volumes associated with ourinterest in Webb Duval. Volumes transported by Webb Duval, net of intercompanyvolumes, were 121,864 MMBtu/d, 118,873 MMBtu/d and 108,640 MMBtu/d for theyears ended December 31 2005, 2004 and 2003, respectively.

(4)           Representsactivities related to the ScissorTail Acquisition from August 1, 2005 through December31, 2005. Segment gross margin per unit amounts for the Mid-ContinentOperations are calculated as the segment gross margin divided by the pipelinethroughput, inlet throughput or NGLs produced, as appropriate. Plant inletthroughput and NGLs produced represents total volumes processed and produced bythe Mid-Continent Operations segment at all plants, including our owned plantsand plants owned by third parties. Plant inlet throughput averaged 65,962 MMBtu/dand NGLs produced averaged 5,500 Bbls/d for plants owned by the Mid-Continent Operationssegment

(5)           Represents the total processing segment gross margindivided by the total inlet throughput or NGLs produced, as appropriate.

(6)           Maintenance capital expenditures are capitalexpenditures employed to replace partially or fully depreciated assets tomaintain the existing operating capacity of our assets and to extend theiruseful lives, or other capital expenditures that are incurred in maintainingexisting system volumes and related cash flows.

(7)           Expansion capital expenditures representcapital expenditures made to expand or increase the efficiency of the existingoperating capacity of our assets. Expansion capital expenditures includeexpenditures that facilitate an increase in volumes within our operations,whether through construction or acquisition. For example, expansion ofcompression facilities to increase throughput capacity or the acquisition ofadditional pipelines is considered expansion capital expenditures. Expendituresthat reduce our operating costs will be considered expansion capitalexpenditures only if the reduction in operating expenses exceeds costreductions typically resulting from routine maintenance. Costs for repairs andminor renewals to maintain facilities in operating condition, and which do notextend the useful life of existing assets, are considered operations andmaintenance expenses (and not expansion capital expenditures) and are expensedas incurred.

*Year Ended December31, 2005 Compared with Year Ended December 31, 2004*

*Texas Gulf Coast Pipelines(formerly Copano Pipelines) Segment Gross Margin.**  *Texas Gulf Coast Pipelines segmentgross margin was $32.8 million for the year ended December 31, 2005 compared to$30.1 million for the year ended December 31, 2004, an increase of $2.7 million,or 9%. The increase was primarily attributable to higher average natural gasprices during the year ended December 31, 2005 compared to the year ended December31, 2004, which resulted in an increase in margins associated with our indexprice-related gas purchase and transportation arrangements. During theyear ended December 31, 2005, the Houston Ship Channel, or HSC, naturalgas index price averaged $7.54 per MMBtu compared to $5.78 per MMBtu during theyear ended December 31, 2004, an increase of $1.76, or 30%. Additionally, aportion of the increase in gross margin for this pipeline segment resulted fromthe acquisitions of our Karnes County Gathering System in September 2004 andour Runge Gathering System in December 2004, the results from which arereflected for the full year of 2005.

*Texas Gulf CoastProcessing (formerly Copano Processing) Segment Gross Margin.**  *Texas Gulf Coast Processing segmentgross margin was $30.2 million for the year ended December 31, 2005 compared to$21.4 million for the year ended December 31, 2004, an increase of $8.8 million,or 41%. For the year ended December 31, 2005, we experienced improvements of$5.4 million in our processing segment gross margin as a result of increasedplant utilization and an improved commodity price environment. For a discussionof the commodity price environment, please read “—How We Evaluate OurOperations—Segment Gross Margin.”  Ourprocessing segment gross margin was further improved during the year ended December31, 2005 as compared to the year ended December 31, 2004 as a result ofincreased conditioning fee revenue of $2.6 million. Additionally, the processingsegment gross margin increased because processing upgrade payments to naturalgas suppliers, including our pipeline affiliates, decreased 

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by $0.8 millionduring the year ended December 31, 2005 as compared to the year ended December 31,2004.

*Mid-Continent OperationsGross Margin.**  *OnAugust 1, 2005, we completed the ScissorTail Acquisition. During the periodfrom August 1, 2005 through December 31, 2005, gross margin for theMid-Continent Operations segment totaled $40.7 million. This segment gatheredor transported an average of 158,334 MMBtu/d of natural gas on its pipelines,processed an average of 106,877 MMBtu/d of natural gas and produced an averageof 9,146 barrels per day of NGLs.

*Corporate Segment GrossMargin.**  *Thecorporate segment gross margin primarily consists of an unrealized gain of $0.4million for the year ended December 31, 2005 primarily related to our commodityrisk management activities that commenced in July 2005 accounted for on amark-to-market basis through October 24, 2005.

*Operations and MaintenanceExpenses.**  *Operationsand maintenance expenses totaled $18.5 million for the year ended December 31,2005 compared to $12.5 million for the year ended December 31, 2004. Theincrease of $6.0 million, or 48%, is primarily attributed to our acquisition ofthe Mid-Continent Operations on August 1, 2005.

*Depreciation andAmortization.**  *Depreciationand amortization totaled $17.1 million for the year ended December 31, 2005compared with $7.3 million for the year ended December 31, 2004, an increase of$9.8 million, or 134%. This increase relates primarily to additionaldepreciation and amortization associated with acquisitions and capitalexpenditures made after December 31, 2004, including the acquisition of ourMid-Continent Operations on August 1, 2005, the purchase and modification ofthe Karnes County Gathering System during September 2004 and the purchase ofand modifications and enhancements made to the Runge Gathering System duringthe fourth quarter of 2004.

*General and AdministrativeExpenses.**  *Generaland administrative expenses totaled $18.2 million for the year ended December 31,2005 compared with $9.2 million for the year ended December 31, 2004, anincrease of $9.0 million, or 98%. The increase primarily relates to (i) theoperations of our Mid-Continent Operations acquired on August 1, 2005 of $1.9 millionand (ii) the costs of being a public company of $6.4 million including (A)costs associated with accounting and legal services, director compensation,investor relations and other consulting services, printing and insurance of$1.0 million, (B) costs related to augmented infrastructure and hiringadditional staff of $2.2 million, (C) costs of preparing and processing tax K-1sto unitholders of $0.5 million, (D) costs associated with Sarbanes-Oxleyreadiness of $1.4 million and (E) non-cash compensation expense related to theamortization of the intrinsic value of restricted units issued to employees anddirectors of $1.3 million. Additionally, we incurred $0.7 million more in 2005as compared to 2004 of expenses related to growth and acquisition initiatives.

*Interest Expense.**  *Interest and other financing coststotaled $20.5 million for the year ended December 31, 2005 compared with $23.2 millionfor the year ended December 31, 2004. Interest expense related to our creditfacilities totaled $14.7 million and $2.6 million for the year ended December 31,2005 and 2004, respectively. Average borrowings under these credit facilitieswere $227.5 million and $61.3 million with average interest rates of 7.6%and 5.3% for 2005 and 2004, respectively. Amortization of debt issue costs totaled$5.8 million and $2.0 million for the year ended December 31, 2005 and 2004,respectively. Amortization of debt issue costs for the year ended December 31,2005 included one-time charges of $1.6 million related to the early terminationof the CPG Credit Agreement and the CHC Facility discussed in Note 7 to theaudited consolidated financial statements. Amortization of debt issue costs forthe year ended December 31, 2004 included a one-time charge of $0.3 millionrelated to the early termination of the then outstanding Texas Gulf CoastProcessing credit facility. Additionally, interest expense for the year ended December31, 2004 included $9.4 million of interest related to the payment-in-kindpreferred units issued to certain pre-offering Investors that held theredeemable preferred units, the accretion of the allocated warrantvalue associated with the redeemable preferred units and payment-in-kindinterest under a subsidiary term loan entered into in 2001. Interest expensefor the year 

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ended December 31,2004 also included write-offs totaling $9.2 million of which (i) $8.9 millionrelated to the remaining discount and issuance costs associated with theredeemable preferred units which were redeemed using proceeds from the initialpublic offering and (ii) $0.3 million related to the remaining discountassociated with our purchase of the warrant issued by one of our subsidiariesto the holder of the term loan. The decrease in interest expense is dueprimarily to our redemption of the redeemable preferred units offset byborrowings under our Credit Facility and Term Loan Facility, discussed in “—Liquidityand Capital Resources—Our Indebtedness.”

*Year Ended December 31, 2004 Compared with Year Ended December31, 2003*

*Texas Gulf Coast Pipelines(formerly Copano Pipelines) Segment Gross Margin.**  *Pipelines segment gross margin was$30.1 million for the year ended December 31, 2004 compared to $27.6 millionfor the year ended December 31, 2003, an increase of $2.5 million, or 9.0%. Theincrease was primarily attributable to higher average natural gas prices duringthe year ended December 31, 2004 compared to the year ended December 31, 2003,which caused an increase in margins associated with our index price-relatedgas purchase and transportation arrangements. During 2004, the HSC natural gasindex price averaged $5.78 per MMBtu compared to $5.24 per MMBtu during 2003,an increase of $0.54, or 10 %. Additionally, a portion of this increase wasrelated to improved contract terms as a result of our contract restructuringefforts discussed above, which was partially offset (i) with milder weatherduring the winter heating portion of the first quarter of 2004, which resultedin lower volumes being sold to utilities under high-margin arrangementsand (ii) the reduction of relatively low-margin transportation volumes in theUpper Gulf Coast and Coastal Waters regions.

*Texas Gulf CoastProcessing (formerly Copano Processing) Segment Gross Margin.**  *Processing segment gross margin was$21.4 million for the year ended December 31, 2004 compared to $3.6 million forthe year ended December 31, 2003, an increase of $17.8 million, or 494.4%. Forthe year ended December 31, 2004, we experienced improvements of $19.9 millionin our processing segment gross margin as the result of increased plantutilization and an improved commodity price environment. For a discussion ofthe commodity price environment, please read “—How We Evaluate Our Operations—SegmentGross Margin.”  As a result ofunfavorable commodity prices in 2003, the Houston Central Processing Plant’soperations were severely curtailed during certain portions of that period. Processingsegment gross margin was further improved as a result of increased conditioningfee revenue of $1.5 million for the year ended December 31, 2004 compared withthe same period in 2003. This increase is attributable to receivingconditioning fee revenues for the full year of 2004 versus a partial year ofreceiving conditioning fee revenues in 2003. The increased processing segmentgross margin was partially offset by an increase in processing upgrade paymentsof $3.6 million to natural gas suppliers, including our pipeline affiliates,for the year ended December 31, 2004 and was the result of increased value ofprocessing in 2004.

*Operations and MaintenanceExpenses.**  *Operationsand maintenance expenses totaled $12.5 million for the year ended December 31,2004 compared with $10.9 million for the year ended December 31, 2003, anincrease of $1.6 million, or 14.7%. The increase was primarily attributable to:

·       higherrepair and maintenance expense totaling $0.6 million at our Houston CentralProcessing Plant ($0.5 million, of which $0.3 million related to paintingcertain facilities, repairing a cooling tower and overhauling certain engines)and in our South Texas Region ($0.1 million);

·       increasedutility costs at our Houston Central Processing Plant of $0.3 million relatedto higher plant utilization in 2004;

·       a$0.3 million increase in contract maintenance services costs for our NGL linebecause in 2004 related reimbursements we received from a third party thatshares our right-of-way were lower than reimbursements we receivedin 2003;

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·       higherenvironmental, health and safety expenses, measurement costs, salaries andbenefits and performance awards of $0.4 million;

·       increasedcosts of approximately $0.1 million related to the Karnes County GatheringSystem and Runge Gathering System that were placed in service in September 2004and December 2004, respectively; and

·       highercompression rental expense of $0.1 million in 2004 as a result of installingadditional compression equipment in our South Texas and Upper Gulf Regionsafter December 31, 2003 offset by lower compression rental expense of $0.2 millionas a result of purchasing certain compression equipment we previous leased.

*Depreciation andAmortization.**  *Depreciationand amortization totaled $7.3 million for the year ended December 31, 2004compared with $6.1 million for the year ended December 31, 2003, an increase of$1.2 million, or 19.7%. This increase relates primarily to additionaldepreciation and amortization associated with capital expenditures made after December31, 2003 including the compression equipment purchased earlier this year, theKarnes County Gathering System purchased during the third quarter of 2004 andmodifications and enhancements made to the Houston Central Processing Plantduring the fourth quarter of 2003. Additionally, this increase includes $0.1million related to pipeline and equipment retirements.

*General and AdministrativeExpenses.**  *Generaland administrative expenses totaled $9.2 million for the year ended December 31,2004 compared with $5.8 million for the year ended December 31, 2003, anincrease of $3.4 million, or 58.6%. The increase was primarily due to (i) costsof augmented infrastructure and hiring of additional staff incurred incontemplation of becoming a public company of $1.8 million, (ii) certainone-time costs related to potential alternatives to our initial public offeringand management incentive payments associated with our initial public offeringof $1.0 million and (iii) expenses of $0.6 million associated with costsof becoming a public company, including accounting, directors, K-1processing, investors relations and insurance expenses.

*Interest Expense.**  *Interest and other financing coststotaled $23.2 million for the year ended December 31, 2004 compared with $12.1 millionfor the year ended December 31, 2003, an increase of $11.1 million, or 92%. Ofthis increase, $3.1 million was primarily the result of our adoption of SFAS No. 150on July 1, 2003, which required that the value of the payment-in-kind preferredunits issued to the redeemable preferred unitholders in lieu of preferreddistributions be recorded as interest expense, whereas before the adoption ofStatement of Financial Accounting Standard, or SFAS No. 150, thisvalue was recorded as a direct increase to accumulated deficit. Similarly, theaccretion of the allocated warrant value associated with the redeemablepreferred units was also recorded as interest expense beginning July 1,2003. Current year interest expense also included write offs totaling$9.2 million of which (i) $8.9 million related to the remainingdiscount and issuance costs associated with the redeemable preferred unitswhich were redeemed using proceeds from the initial public offering and (ii) $0.3 millionrelated to the remaining discount associated with our purchase of the warrantissued by one of our subsidiaries to the holder of the term loan. This increasewas partially offset by $1.2 million of lower interest expense related toour credit facilities as a result of lower debt outstanding during the year andlower interest rates on the outstanding borrowings.

**General Trends andOutlook**

Our gross margins areinfluenced by the price of natural gas and by drilling activity in ouroperating regions. Increases in natural gas prices generally have a positiveimpact on our gross margins and conversely, a reduction in natural gas pricesnegatively impacts our gross margins. On average, natural gas prices for thelast half of 2004 trended upward, and full-year 2004 average natural gas priceswere higher than those in the first half of 2004. Average natural gasprices for 2005 were higher than the average full-year price in 2004. Volumesof natural gas on our pipelines also impact our gross margins. Increases in 

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volumesgathered or transported positively impact our gross margins and conversely,reductions in volumes gathered or transported negatively impact our grossmargins. Higher natural gas prices typically encourage drilling activity in ouroperating regions. We believe that natural gas prices will continue tofluctuate over the next twelve months, but will remain at levels sufficient toencourage high levels of drilling activity.

Our gross margins are alsoinfluenced by the price of NGLs and the content of NGLs contained in naturalgas delivered to us at our plants. Increases in NGL prices have a positiveimpact on our gross margins and, conversely, a reduction in NGL prices negativelyimpacts our gross margins. On average, NGL prices for the last half of 2004trended upward and full-year 2004 NGL prices were higher than those in thefirst half of 2004. Average NGL prices for 2005 were higher than the full-yearaverage price in 2004. The content of NGLs in natural gas delivered to us atour plants also impacts our gross margins. Increases in the content of NGLs inthe natural gas delivered to our plants positively impacts our gross margins ifthe price of NGLs exceeds the cost of the natural gas required to extract suchNGLs. Conversely, reductions in the NGL content of gas delivered to our plantsnegatively impact our gross margins under such circumstances. We believe thatNGL prices will continue to fluctuate in 2006, but at levels generallyconsistent with current levels.

In addition to operatingand maintenance expenses, general and administrative expenses and maintenancecapital expenditures, our distributable cash flow is impacted by the interestexpense we pay on our indebtedness. Currently, interest rates on ouroutstanding borrowings fluctuate based on reserve-adjusted interbank offeredmarket rates. Increases in interest rates have a negative impact on ourdistributable cash flow, and, conversely, decreases in interest rates have apositive impact on distributable cash flow. Interest rates for 2004 and 2005have trended upwards.

**Impact of Inflation**

Inflation in the UnitedStates has been relatively low in recent years and did not have a materialimpact on our results of operations for the periods presented. Although theimpact of inflation has not been significant in recent years, it is still afactor in the United States economy and may increase the cost to acquire orreplace property, plant and equipment and may increase the cost of labor andsupplies, and capital available to us. To the extent permitted by competition,regulation and our existing agreements, we may pass along increased costs toour customers in the form of higher fees.

**Liquidityand Capital Resources**

Cash generated fromoperations, borrowings under our credit facility and funds from equity and debtofferings are our primary sources of liquidity. We believe that funds fromthese sources should be sufficient to meet both our short-term working capitalrequirements and our long-term capital expenditure requirements. Our ability topay distributions to our unitholders, to fund planned capital expenditures andto make acquisitions will depend upon our future operating performance, andmore broadly, on the availability of equity and debt financing, which will beaffected by prevailing economic conditions in our industry and financial,business and other factors, some of which are beyond our control.

*Off-Balance SheetArrangements.**  *Wehad no off-balance sheet arrangements as of December 31, 2005.

*Capital Requirements.**  *The natural gas gathering,transmission, and processing businesses are capital-intensive, requiringsignificant investment to maintain and upgrade existing operations. Our capitalrequirements have consisted primarily of, and we anticipate will continue tobe:

·       maintenancecapital expenditures, which are capital expenditures employed to replacepartially or fully depreciated assets to maintain the existing operatingcapacity of our assets and to extend their useful lives, or other capitalexpenditures that are incurred in maintaining existing system volumes andrelated cash flows; and

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·       expansioncapital expenditures such as those to acquire additional assets to grow ourbusiness, to expand and upgrade gathering systems, transmission capacity,processing plants, and to construct or acquire new pipelines, or processingplants.

Given our objective ofgrowth through acquisitions, we anticipate that we will continue to investsignificant amounts of capital to grow and acquire assets. We actively considera variety of assets for potential acquisitions. For a discussion of the primaryfactors we consider in deciding whether to pursue a particular acquisition,please read “—Our Growth Strategy—Acquisition Analysis.”

During the year ended December 31,2005, our capital expenditures totaled $493.0 million, consisting of$487.6 million of expansion capital and $5.4 million of maintenancecapital, including expenditures associated with the ScissorTail Acquisition,net of cash acquired. We funded our capital expenditures with funds fromoperations, borrowings under our credit facilities and the issuance ofadditional equity. Additional expansion capital expenditures related tocompleting the integration of the Runge Gathering System, purchasingcompressors and constructing well interconnects to attach volumes in new areas.We expect to fund future capital expenditures with funds generated from ouroperations, borrowings under our credit facilities and the issuance of additionalequity or debt as appropriate given market conditions. We anticipate expendingapproximately $8.0 million to $9.0 million of maintenance capital over the next12 months.

*Total Contractual CashObligations.**  *Asummary of our total contractual cash obligations as of December 31, 2005,is as follows:

| ** **                          | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------|------------|------------------------------------------|------------|
| **Type of Obligation**    | ** ** | ** **                               | ** ** | **Total  Obligation** | ** ** | **Within  1 Year** | ** ** | **2-3 Years** | ** ** | **4-5 Years** | ** ** | **More than  5 years** | ** ** |
| ** **                          | ** ** | **(in thousands)**                  | ** ** |
| Long-term  debt                     |       | $                                        | 398,000    |   | $ | — |   | $ | — |   | $ | 228,000 |   | $ | 170,000 |   |
| Interest                            |       | 281,809                                  |       | 32,344 |   | 64,689 |   | 64,689 |   | 120,087 |   |
| Operating Leases                    |       | 3,966                                    |       | 1,975 |   | 1,474 |   | 517 |   | — |   |
| Total contractual cash  obligations |       | $                                        | 683,775    |   | $ | 34,319 |   | $ | 66,163 |   | $ | 293,206 |   | $ | 290,087 |   |
|                                     |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Asummary of our total contractual cash obligations as of February 7, 2006,the date we completed the issuance of the Senior Notes, is as follows:

| ** **                          | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------|------------|------------------------------------------|------------|
| **Type of Obligation**    | ** ** | ** **                               | ** ** | **Total  Obligation** | ** ** | **Within  1 Year** | ** ** | **2-3 Years** | ** ** | **4-5 Years** | ** ** | **More than  5 years** | ** ** |
| ** **                          | ** ** | **(in thousands)**                  | ** ** |
| Long-term  debt                     |       | $                                        | 385,000    |   | $ | — |   | $ | — |   | $ | 160,000 |   | $ | 225,000 |   |
| Interest                            |       | 254,504                                  |       | 27,856 |   | 55,713 |   | 55,713 |   | 115,222 |   |
| Operating Leases                    |       | 3,669                                    |       | 1,678 |   | 1,474 |   | 517 |   | — |   |
| Total contractual cash  obligations |       | $                                        | 643,173    |   | $ | 29,534 |   | $ | 57,187 |   | $ | 216,230 |   | $ | 340,222 |   |
|                                     |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

In addition to thecontractual obligations noted in the table above, we have both fixed andvariable contracts to purchase natural gas, which were executed in connectionwith our natural gas marketing activities. As of December 31, 2005, we hadfixed contractual commitments to purchase 169,725 MMBtu of natural gas in January 2006.All of these contracts were based on index-related prices. Using theseindex-related prices at December 31, 2005, we had total commitmentsto purchase $1.3 million of natural gas under such agreements. Ourcontracts to purchase variable quantities of natural gas at index-relatedprices range from one month to the life of the dedicated production. During December2005, we purchased 8,028,881 MMBtu of natural gas under such contracts.

For a discussion of ourreal property leases, please read Item 1 “Business—Office Facilities.”

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*Cash Flows.*

Thefollowing summarizes our cash flows for each of the three years ended December 31,2005, as reported in the historical consolidated statements of cash flows foundin Item 8 of this Annual Report.

| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                            | ** ** | **(in thousands)**                    | ** ** |
| Net cash provided  by operating activities            |       | $                                          | 280        |   | $ | 17,697 |   | $ | 15,296 |   |
| Net cash used in  investing activities                |       | (491,708                                   | )          | (8,920 | ) | (6,192 | ) |
| Net cash provided  by (used in) financing activities  |       | 509,710                                    |       | (6,369 | ) | (9,633 | ) |
| Net increase  (decrease) in cash and cash equivalents |       | 18,282                                     |       | 2,408 |   | (529 | ) |
| Cash and cash  equivalents at beginning of year       |       | 7,015                                      |       | 4,607 |   | 5,136 |   |
| Cash and cash  equivalents at end of year             |       | $                                          | 25,297     |   | $ | 7,015 |   | $ | 4,607 |   |

 

*Operating:*

| ** **                                               | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                               | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                               | ** ** | **(in thousands)**                    | ** ** |
| Net income (loss)                                        |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Depreciation and  amortization                           |       | 22,775                                     |       | 9,287 |   | 7,031 |   |
| Equity in  (earnings) loss from unconsolidated affiliate |       | (927                                       | )          | (419 | ) | 127 |   |
| Deferred stock  compensation, unrealized gain and other  |       | 1,309                                      |       | (8 | ) | — |   |
| Non-cash interest  expense                               |       | —                                     |       | 17,132 |   | 8,135 |   |
| Cash (used in)  provided by working capital              |       | (53,229                                    | )          | (7,380 | ) | 4,720 |   |
| Net cash provided by  operating activities               |       | $                                          | 280        |   | $ | 17,697 |   | $ | 15,296 |   |

 

The overall decrease of $17.4 million inoperating cash flow for the year ended December 31, 2005 compared to theyear ended December 31, 2004 was primarily the result of an increase innet income of $31.3 million, a decrease in non-cash items of$2.9 million and a increase in the changes in working capital components(exclusive of cash and cash equivalents) of $45.8 million. This increasein the changes in working capital components (exclusive of cash and cashequivalents) was primarily the result of increases in accounts receivable andprepaid items of $2.2 million and risk management assets of$42.6 million and a decrease in accounts payable of $1.0 million.

The overall increase of $2.4 million in operatingcash flow for the year ended December 31, 2004 compared to the year ended December 31,2003 was primarily the result of a decrease in net loss and non-cash itemsitemized above of $14.7 million and a decrease in the changes in workingcapital components (exclusive of cash and cash equivalents) of$12.3 million. This decrease in the changes in working capital components(exclusive of cash and cash equivalents) was primarily the result of decreasedaccounts payable as a result of the resolution of a dispute between a royaltyowner and an operator from which we purchase natural gas. As a result of thedispute, we had suspended payments to the operator. Upon receiving notice thatthe parties had substantially resolved their dispute, we used additional cashduring the second quarter of 2004 when we released approximately$6.1 million in suspended funds to pay the operator for natural gas we hadpurchased during 2002, 2003 and early 2004.

We believe that we will continue to have adequateliquidity to fund future recurring operating and investing activities. Ourprimary cash requirements consist of normal operating expenses, capitalexpenditures to sustain existing operations and revenue generatingexpenditures, interest payments on our credit facilities, distributions to ourunitholders and acquisitions of new assets or businesses. Short-term cashrequirements, such as operating expenses, capital expenditures to sustainexisting operations and quarterly distributions to our unitholders, areexpected to be funded through operating cash flows. 

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Long-term cashrequirements for expansion projects and acquisitions are expected to be fundedby several sources, including cash flows from operating activities, borrowingsunder our credit facilities, and the issuance of additional equity and debtsecurities, as appropriate. Our ability to complete future debt and equityofferings and the timing of any such offerings will depend on various factors,including prevailing market conditions, interest rates, our financial conditionand our credit rating at the time.

*Investing:*   Netcash used in investing activities was $491.7 million for the year ended December 31,2005 compared to $8.9 million for the year ended December 31, 2004. Capitalexpenditures for 2005 include costs related to our ScissorTail Acquisition on August 1,2005 and several small pipeline systems, completing the integration of theRunge Gathering System, building well interconnects, purchasing compressors,constructing a monitoring and control system for our NGL line and upgradingdehydration facilities at the inlet to the cryogenic portion of our HoustonCentral Processing Plant slightly offset by the release of restricted cash. Capitalexpenditures in 2004 include expenditures for the acquisition of compressionequipment, the Karnes County Gathering System and the Runge Gathering System aswell as the continued development and installation of our SCADA system.

Capital expenditures for 2003 were $6.2 millionwhich included capital expenditures for the modification to our Houston CentralProcessing Plant and the development of our SCADA system.

*Financing:*   Netcash provided by financing activities totaled $509.7 million during theyear ended December 31, 2005 and included (i) net borrowings underour credit facilities of $341.0 million, (ii) net proceeds from theprivate placement of common units and Class B units of $198.9 millionand (iii) capital contributions of $4.2 million from our pre-offeringinvestors and from the exercise of unit options offset by (a) distributionsto our unitholders of $23.4 million, (b) deferred financing costs of$9.8 million and (c) $1.2 million of payments under short-termfinancing arrangements.

Cash used in financing activities for the year ended December 31,2004, exclusive of our initial public offering proceeds, included netborrowings of long-term debt prior to our initial public offering of$3.5 million reduced by payments related to (i) cash distributionspaid to the pre-offering common and preferred unitholders of $4.0 million,(ii) $3.4 million of offering costs, and (iii) debt financingrelated costs of $2.5 million.

Wereceived net proceeds from our initial public offering, includingproceeds from the exercise of the underwriters’ over-allotment option, of$106.9 million after deducting underwriting commissions anddiscounts. We used these proceeds to

·       redeem our redeemablepreferred units from pre-offering investors for $78.1 million,

·       reduce existingindebtedness under our Copano Pipelines credit agreement, discussed below, by$6.0 million,

·       reduce the overall existingindebtedness of our Texas Gulf Coast Processing segment, discussed below, by$7.0 million,

·       redeem common units fromcertain existing investors for $13.9 million,

·       pay other obligations of$1.0 million, and

·       paycertain additional expenses of our initial public offering of$0.9 million.

For the year ended December 31, 2003, cash usedin financing activities was primarily attributable to our net repayment of$7.8 million in long-term debt, $0.8 million of offering costs,$0.8 million of cash distributions paid to our preferred unitholders and$0.2 million of debt issue costs and the repayment of other long-termobligations.

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*CashDistributions and Reserves:**  *Fora discussion of our cash distributions and reserves, please read Item 5 “Marketfor Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchasesof Equity Securities” of this Annual Report.

We believe thatanticipated cash from operations and borrowings under our senior securedrevolving credit facility will be sufficient to meet our liquidity needs forthe foreseeable future. If our plans or assumptions change or are inaccurate,or we make any acquisitions, we may need to raise additional capital. We maynot be able to raise additional funds or may not be able to raise such funds onfavorable terms.

*Description of OurIndebtedness*

*CreditRatings.**  *At February 15, 2006, our CorporateFamily Ratings was B1, the Senior Notes were rated B2 and our Speculative GradeLiquidity rating was SGL-3 with a stable outlook as assigned by Moody’sInvestor Services. Our Corporate Family Ratings was BB- and the Senior Noteswere rated B with a stable outlook as assigned by Standard and Poor’s.

*New$350 Million Credit Facility.**  *OnAugust 1, 2005, we entered into a new $350 million senior securedrevolving credit facility (the “Credit Facility”) with Bank of America, N.A.,as Administrative Agent, Banc of America Securities LLC, as Sole Lead Arrangerand Sole Book Manager and a group of financial institutions, as lenders. TheCredit Facility includes a $25 million sublimit for the issuance ofstandby letters of credit and matures on July 31, 2010.

On August 1, 2005, we initially borrowed $232.0million under the Credit Facility to: (i) partially finance theScissorTail Acquisition and (ii) to repay in full indebtedness outstandingunder the CPG Credit Agreement and the CHC Facility. Additionally, inconnection with our ScissorTail Acquisition, a $0.9 million standby letterof credit was assumed by us, which remains outstanding at December 31,2005. Borrowings under the Credit Facility are available for acquisitions, capitalexpenditures, working capital and general corporate purposes. The CreditFacility does not provide for the type of working capital borrowings that wouldbe eligible, pursuant to our limited liability company agreement, to beconsidered available cash distributable to our unitholders. The Credit Facilityis available to be drawn on and repaid without restriction so long as we are incompliance with the terms of the Credit Facility, including certain financialcovenants.

The Credit Facility contains various covenants thatlimit our and certain of our operating subsidiaries’ ability to grant certainliens; make certain loans and investments; make certain capital expendituresoutside our current lines of business or certain related lines of business;make distributions other than from available cash (as defined in our limitedliability company agreement); merge or consolidate with or into a third party;or engage in certain asset dispositions, including a sale of all orsubstantially all of our assets. Additionally, the Credit Facility limits ourand certain of our operating subsidiaries’ ability to incur additionalindebtedness with certain exceptions, including under the Term Loan Facility(as discussed below), purchase money indebtedness and indebtedness related tocapital or synthetic leases not to exceed $5.0 million, unsecured indebtednessnot to exceed $5.0 million and unsecured indebtedness qualifying assubordinated debt.

The Credit Facilityalso contains covenants, which, among other things, require us and certain ofour subsidiaries, on a consolidated basis, to maintain specified ratios orconditions as follows:

·       EBITDAto interest expense of not less than 2.5 to 1.0 through September 30,2005, 2.75 to 1.0 from December 31, 2005 through June 30, 2006 and3.0 to 1.0 thereafter;

·       EBITDAminus maintenance capital expenditures to consolidated fixed charges of notless than 1.5 to 1.0 through September 30, 2005 and 1.75 to 1.0thereafter;

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·       totaldebt to EBITDA of not more than 5.5 to 1.0 through September 30, 2005, 5.0to 1.0 from December 31, 2005 through June 30, 2006 and 4.75 to 1.0thereafter; and

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0 through September 30,2005 and 3.5 to 1.0 thereafter.

EBITDA for the purposes of the Credit Facility is ourEBITDA with certain negotiated adjustments.

Based upon the senior debt to EBITDA ratio calculatedas of December 31, 2005 (utilizing trailing four quarters’ EBITDA asdefined under the Credit Facility), we have approximately $122.0 millionof unused capacity under the Credit Facility.

The obligations under the Credit Facility are securedby first priority liens on substantially all of our assets and substantiallyall of the assets of our subsidiaries (other than Webb Duval, Southern Dome andcertain subsidiaries with insignificant assets). Additionally, the obligationsunder the Credit Facility are guaranteed by substantially all of oursubsidiaries (other than Webb Duval, Southern Dome and certain subsidiarieswith insignificant assets).

At our election, interest under the Credit Facility isdetermined by reference to (i) the British Bankers Association LIBOR rate,or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum or (ii) thehigher of the federal funds rate plus 0.5% or the prime rate plus, in eithercase, an applicable margin between 0.25% and 1.25% per annum. Interest ispayable quarterly for prime rate loans and at the applicable maturity date forLIBOR loans, except that if the interest period for a LIBOR loan is nine months,interest will be paid at the end of each three-month period.

If an event ofdefault occurs under the Credit Facility, the lenders would be able toaccelerate the maturity of the obligations outstanding under the CreditFacility and exercise other rights and remedies. Each of the following would bean event of default:

·       failureto pay any principal when due or any interest, fees or other amount withincertain grace periods;

·       failureto perform or otherwise comply with the covenants in the credit agreement orother loan documents, subject, in certain instances, to certain grace periods;

·       defaultby us on the payment of any other indebtedness in excess of $5.0 million, orany default in the performance of any obligation or condition with respect tosuch indebtedness beyond the applicable grace period if the effect of thedefault is to permit or cause the acceleration of the indebtedness;

·       bankruptcyor insolvency events involving us or our subsidiaries;

·       theentry of, and failure to pay, one or more adverse judgments in excess of $5.0million against which enforcement proceedings are brought or that are notstayed pending appeal; and

·       achange of control (as defined in the Credit Facility).

The effective average interest rate on borrowingsunder the Credit Facility was 6.15% and the quarterly commitment fee on theunused portion of the Credit Facility was 0.25% as of December 31, 2005. Interestand other financing costs related to the Credit Facility totaled$6.6 million for the period from August 1, 2005 through December 31,2005. Costs incurred in connection with the establishment of this creditfacility are being amortized over the term of the Credit Facility, and as of December 31,2005, the unamortized portion of debt issue costs totaled $4.7 million.

Management believes that we are in compliance with thecovenants under the Credit Facility as of December 31, 2005. If an eventof default exists under the Credit Facility, the lenders will be able toaccelerate the maturity of the credit agreement and exercise other rights andremedies.

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*TermLoan Facility.**  *On August 1, 2005, we enteredinto a $170 million senior unsecured term loan facility (the “Term LoanFacility”) with Banc of America Bridge LLC, as the Lender and Banc of AmericaSecurities LLC, as Sole Lead Arranger and Sole Book Manager. The proceeds fromthe Term Loan Facility were used to pay a portion of the purchase price of theScissorTail Acquisition. On February 7, 2006, we used the proceeds fromthe issuance of the Senior Notes to repay and terminate this term loanfacility, as discussed below.

The effective average interest rate on borrowingsunder the Term Loan Facility was 9.29% as of December 31, 2005. Interestand other financing costs related to the Term Loan Facility totaled$9.9 million for the period from August 1, 2005 through December 31,2005. Costs incurred in connection with the establishment of this creditfacility were being amortized over the estimated term of the Term LoanFacility, and as of December 31, 2005, the unamortized portion of debtissue costs totaled $0.6 million.

*SeniorNotes.**  *On February 7,2006, we completed the sale of the Senior Notes due 2016. We used the netproceeds, after deducting initial purchaser discounts and offering costs, ofapproximately $219.4 million to (i) repay and terminate our Term LoanFacility discussed above, (ii) reduce the balance outstanding under ourCredit Facility by $68.0 million and (iii) pay expenses of approximately$1.4 million.

The Senior Notes represent our senior unsecuredobligations and rank pari passu in right of payment with all our other presentand future senior indebtedness. The Senior Notes are effectively subordinatedto all of our secured indebtedness to the extent of the value of the assetssecuring the indebtedness and to all existing and future indebtedness andliabilities, including trade payables, of our non-guarantor subsidiaries (otherthan indebtedness and other liabilities owed to us, if any). The Senior Notesrank senior in right of payment to all of our future subordinated indebtedness.

The Senior Notes are jointly and severally guaranteedby all of our current wholly-owned subsidiaries (other than Copano EnergyFinance Corporation, a wholly-owned subsidiary, and the co-issuer of the SeniorNotes) and by certain of our future subsidiaries. The subsidiary guaranteesrank equally in right of payment with all of the existing and future seniorindebtedness of our guarantor subsidiaries, including their guarantees of ourother senior indebtedness. The subsidiary guarantees are effectivelysubordinated to all existing and future secured indebtedness of our guarantorsubsidiaries to the extent of the value of the assets securing thatindebtedness and to all existing and future indebtedness and other liabilities,including trade payables, of any non-guarantor subsidiaries (other thanindebtedness and other liabilities owed to our guarantor subsidiaries). Thesubsidiary guarantees rank senior in right of payment to any futuresubordinated indebtedness of our guarantor subsidiaries.

Before March 1, 2009, we may, at any time or fromtime to time, redeem up to 35% of the aggregate principal amount of the SeniorNotes with the net proceeds of a public or private equity offering at 108.125%of the principal amount of the Senior Notes, plus any accrued and unpaidinterest, if at least 65% of the aggregate principal amount of the notesremains outstanding after such redemption and the redemption occurs within 120days of the date of the closing of such equity offering.

TheSenior Notes are redeemable, at our option, in whole or in part, at any time onor after March 1, 2011, in each case at the redemption prices described inthe table below, together with any accrued and unpaid interest to the date ofthe redemption.

| **Year**            | ** ** | ** ** | ** ** | **Percentage** | ** ** |
|---------------------|------------|------------|------------|----------------|------------|
| 2011                |       |       | 104.0625   | %              |       |
| 2012                |       |       | 102.7083   | %              |       |
| 2013                |       |       | 101.3542   | %              |       |
| 2014 and thereafter |       |       | 100.0000   | %              |       |

 

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The Indenturegoverning the Senior Notes contains covenants that, among other things, limitour ability and the ability of our restricted subsidiaries to:

·       sellassets;

·       paydistributions on, redeem or repurchase our units or redeem or repurchase oursubordinated debt;

·       makeinvestments;

·       incuror guarantee additional indebtedness or issue preferred units;

·       createor incur certain liens;

·       enterinto agreements that restrict distributions or other payments from ourrestricted subsidiaries to us;

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

·       engagein transactions with affiliates;

·       createunrestricted subsidiaries; and

·       enterinto sale and leaseback transactions.

These covenants are subject to important exceptionsand qualifications and, additionally, if the Senior Notes achieve an investmentgrade rating from each of Moody’s Investors Service, Inc. and Standard &Poor’s Ratings Services, many of these covenants will terminate.

We have agreed to conducta registered exchange offer for the Senior Notes or to cause to becomeeffective a shelf registration statement providing for resales of the SeniorNotes. If we fail to satisfy these obligations on a timely basis, we have agreedto pay additional interest to holders of the Senior Notes under somecircumstances.

**Recent AccountingPronouncements**

*Share-BasedPayment.**  *InDecember 2004, the Financial Accounting Standards Board, or FASB, issuedSFAS No. 123 (revised 2004), or SFAS No. 123(R), “Share Based Payment”which establishes accounting standards for all transactions in which an entityexchanges its equity instruments for goods or services. SFAS No. 123(R) focusesprimarily on accounting for transactions with employees, and carries forwardwithout change to prior guidance for share-based payments for transactions withnon-employees. SFAS No. 123(R) eliminates the intrinsic valuemeasurement objective in Accounting Principles Board, or APB, Opinion No. 25and generally requires us to measure the cost of employee services received inexchange for an award of equity instruments based on the fair value of theaward on the date of the grant.

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The standard requires grant date fair value to beestimated using either an option-pricing model that is consistent with theterms of the award or a market observed price, if such a price exists. Suchcost must be recognized over the period during which an employee is required toprovide services in exchange for the award (which is usually the vestingperiod). The standard also requires us to estimate the number of instrumentsthat will ultimately be issued, rather than accounting for forfeitures as theyoccur. We are required to apply SFAS No. 123(R) to all awardsgranted, modified or settled in the first reporting period after January 1,2006. We are also required to use either the “modified prospective method” orthe “modified retrospective method.” Under the modified prospective method, wemust recognize compensation cost for all awards granted after we adopt thestandard and for the unvested portion of previously granted awards that areoutstanding on that date. Under the modified retrospective method, we mustrestate previously issued financial statements to recognize the amounts wepreviously calculated and reported on a pro forma basis, as if the priorstandard had been adopted. Under both methods, we are permitted to use either astraight line or an accelerated method to amortize the cost as an expense forawards with graded vesting. We have adopted this standard effective January 1,2006.

We have commenced the analysis of the impact of SFAS No. 123(R),but have not yet decided whether we will use the modified prospective method orelect to use the modified retrospective method or whether we will elect to usestraight line amortization or an accelerated method. Accordingly, we cannotcurrently quantify with precision the effect that this standard would have onour financial position or results of operations in the future, except that weprobably will recognize a greater expense for any awards that we may grant inthe future than we would using the current guidance. The adoption of thisstatement is not expected to have a material impact on our financial position,results of operations or cash flows.

*Exchangesof Nonmonetary Assets as Amendment of APB No. 29.**  *In December 2004,the FASB issued SFAS No. 153, “*Exchangesof Nonmonetary Assets an amendment of APB No. 29*.”  This statement amends APB No. 29 toeliminate the exception for nonmonetary exchanges of similar productive assetsand replaces it with a general exception for exchanges of nonmonetary assetsthat do not have commercial substance. The statement specifies that anonmonetary exchange has commercial substance if the future cash flows of theentity are expected to change significantly as a result of the exchange. Weadopted this statement beginning July 1, 2005. The adoption of thisstatement had no impact on our previously issued financial statements and isnot expected to have a material impact on future financial statements.

*Accountingfor Conditional Asset Retirement Obligations, an interpretation of FASBStatement No. 143.*   In March 2005, the FASB issued FASB Interpretation No. (“FIN”)47, “Accounting for Conditional AssetRetirement Obligations, an interpretation of FASB Statement No. 143.”  FIN 47 clarifies that the term,conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,”refers to a legal obligation to perform an asset retirement activity in whichthe timing and/or method of settlement are conditional upon a future event thatmay or may not be within the control of the entity. Even though uncertaintyabout the timing and/or method of settlement exists and may be conditional upona future event, the obligation to perform the asset retirement activity isunconditional. In these circumstances, we are required to determine if there isa range of potential settlement dates and the probabilities associated withthis range based on a variety of factors including the entity’s past practice,industry practice, management’s intent, and the assets economic life. The fairvalue of a liability for the conditional asset retirement obligation should berecognized when incurred generally upon acquisition, construction ordevelopment or through the normal operation of the asset. SFAS No. 143acknowledges that in some cases, sufficient information may not be available toreasonably estimate the fair value of an asset retirement obligation. FIN 47also clarifies when an entity would have sufficient information to reasonablyestimate the fair value of an asset retirement obligation. We adoptedFIN 47 effective December 31, 2005 and the adoption did not have asignificant impact on our financial position, results of operations or cashflows.

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*AccountingChanges and Error Corrections.**  *In May 2005, the FASB issued SFAS No. 154, “*Accounting Changes and Error Corrections.*”  SFAS No. 154 requires companies torecognize changes in accounting principle, including changes required by a newaccounting pronouncement when the pronouncement does not include specifictransition provisions, retrospectively to prior periods’ financial statements. SFASNo. 154 is effective for accounting changes and corrections of errors madein fiscal years beginning after December 15, 2005. We do not believe thatthe adoption of SFAS No. 154 will have a material effect on our financialposition or results of operations.

*Accounting for Purchasesand Sales of Inventory with the Same Counterparty.**  *In September 2005,the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on theissue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13,*“Accounting for Purchases and Sales ofInventory with the Same Counterparty”* (Issue 04-13). As partof Issue 04-13, the EITF is requiring that all buy/sell arrangements bereflected on a net basis, such that the purchase and sale are netted and shownas either a net purchase or a net sale in the income statement. Thisrequirement is effective for new arrangements entered into after March 31,2006. If this requirement had been effective for the years ended December 31,2005 and 2004, the reported natural gas sales revenues and the reported cost ofnatural gas and natural gas liquids would be reduced by the amounts shown infootnotes (1) and (2) to the consolidated statements of operations. Wedo not expect that the adoption of Issue 04-13 will have a materialeffect on our financial position, results of operations or cash flows.

**SignificantAccounting Policies and Estimates**

The selection and application of accounting policiesis an important process that has developed as our business activities haveevolved and as the accounting rules have developed. Accounting rules generallydo not involve a selection among alternatives, but involve an implementationand interpretation of existing rules, and the use of judgment applied to thespecific set of circumstances existing in our business. We make every effort toproperly comply with all applicable rules on or before their adoption, andwe believe the proper implementation and consistent application of theaccounting rules are critical. For further details on our accountingpolicies, please read Notes 2 and 3 to the Consolidated FinancialStatements contained in Item 8 in this Annual Report.

In May 2003, the FASB issued SFAS No. 150, *Accounting for Certain Financial Instruments withCharacteristics of Both Liabilities and Equity*. SFAS No. 150requires that certain financial instruments previously classified as equity beclassified as liabilities or, in some cases, as assets. We adopted SFAS No. 150effective July 1, 2003 and classified our redeemable preferred units as aliability and recorded the value of the paid-in-kind, or PIK, preferred unitdistributions issued to the redeemable preferred unitholders as interestexpense, whereas prior to the adoption of SFAS No. 150, thesedistributions were recorded as a direct reduction of the accumulated deficit. Additionally,the accretion of the allocated value assigned to the warrants held by theholders of the redeemable preferred units was recorded as interest expense uponadoption of SFAS No. 150 whereas previously this accretion was recorded asa direct reduction of paid-in-capital. Please read Notes 2 and 8 to ourConsolidated Financial Statements contained in Item 8 in this AnnualReport.

*Impairmentof Long-Lived Assets.**  *Inaccordance with SFAS No. 144, *Accountingfor the Impairment or Disposal of Long-Lived Assets*, we evaluate thelong-lived assets, including related intangibles, of identifiable businessactivities for impairment when events or changes in circumstances indicate, inmanagement’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onmanagement’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. Estimating the fairvalue for the assets to determine if impairment has occurred, and recording aprovision for loss if the carrying value is greater than fair value, determinethe amount of the impairment recognized. For assets identified to be disposedof in the future, the carrying value of these assets is compared to theestimated fair value less the 

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cost to sell to determineif impairment is required. Until the assets are disposed of, an estimate of thefair value is recalculated when related events or circumstances change.

When determiningwhether impairment of one of our long-lived assets has occurred, we mustestimate the undiscounted cash flows attributable to the asset or asset group. Ourestimate of cash flows is based on assumptions regarding the asset and futureNGL product and natural gas prices. The amount of reserves and drillingactivity are dependent in part on natural gas prices. Projections of gasvolumes and future commodity prices are inherently subjective and contingentupon a number of variable factors, including but not limited to:

·       changesin general economic conditions in regions in which our products are located;

·       theavailability and prices of raw natural gas supply;

·       ourability to negotiate favorable sales agreements;

·       ourdependence on certain significant customers, producers, gatherers, andtransporters of natural gas; and

·       competitionfrom other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptionsor factors could materially affect our cash flows, which could require us torecord an impairment of an asset.

*AssetRetirement Obligation.**  *SFASNo. 143, *Accounting for AssetRetirement Obligations*requires entities to record the fair value ofa liability for legal obligations associated with the retirement obligations oftangible long-lived assets in the period in which the obligation is incurredand can be reasonably estimated. When the liability is initially recorded, acorresponding increase in the carrying amount of the related long-lived assetwould be recorded. Over time, accretion of the liability is recognized eachperiod, and the capitalized cost is depreciated over the useful life of therelated asset. Upon settlement of the liability, an entity either settles theobligation for its recorded amount or incurs a gain or loss on settlement. Thestandard was effective for us on January 1, 2003. Under the implementationguidelines of SFAS No. 143, we reviewed our long-lived assets for assetretirement obligations, or AROs, and based on our analysis, we determined wewere not required to recognize any potential liabilities under SFAS 143. However,as discussed above, effective December 31, 2005, we adopted FIN 47which established criteria for conditional ARO’s. Conditional ARO’s are thosewhere a firm obligation exists and there is uncertainty about either the timingor method of settlement. In these circumstances, we are required to determineif there is a range of potential settlement dates and the probabilitiesassociated with this range based on a variety of factors including the entity’spast practice, industry practice, management’s intent, and the assets economiclife. We have made our best determination of the settlement costs and timingfor those assets with legal or statutory retirement obligations, and haverecorded a conditional ARO asset and liability at December 31, 2005. Theseliabilities include ARO liabilities related to those (i) right-of-wayeasements over property not owned by us, and (ii) regulatory requirementswhere a legal or contractual obligation exists upon abandonment of the relatedfacility. Future amortization of the ARO asset and accretion of the AROliability will be recognized in earnings. None of our assets are legally restrictedfor purposes of settling asset retirement obligations.

*EquityMethod of Accounting.**  *Althoughwe own a 62.5% partnership interest in Webb Duval and a majority interest inSouthern Dome, we account for both of these investments using the equity methodof accounting because the minority general partners or members have substantiveparticipating rights with respect to the management of Webb Duval and SouthernDome.

*Revenue Recognition.**  *Our natural gas and NGL revenue isrecognized in the period when the physical product is delivered to the customerat contractually agreed-upon pricing. Transportation, compression andprocessing-related revenues are recognized in the period when the serviceis provided.

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**Forward-Looking Statements**

This Annual Reportcontains certain “forward-looking statements” within the meaning of the federalsecurities laws. All statements, other than statements of historical factincluded in this Annual Report, including, but not limited to, those under “—Results of Operation” and “—Liquidity and Capital Resources” areforward-looking statements. Statementsincluded in this Annual Report that are not historical facts, but that addressactivities, events or developments that we expect or anticipate will or mayoccur in the future, including things such as references to future goals orintentions or other such references are forward-looking statements. Thesestatements can be identified by the use of forward-looking terminologyincluding “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” orsimilar words. These statements include statements related to plans for growthof the business, future capital expenditures and competitive strengths andgoals. We make these statements based on our past experience and our perceptionof historical trends, current conditions and expected future developments aswell as other considerations we believe are appropriate under the circumstances.Whether actual results and developments in the future will conform to ourexpectations is subject to numerous risks and uncertainties, many of which arebeyond our control. Therefore, actual outcomes and results couldmaterially differ from what is expressed, implied or forecast in thesestatements. Any differences could be caused by a number of factors, including,but not limited to:

·       Ourability to successfully integrate any acquired assets or operations;

·       Thevolatility of prices and market demand for natural gas and natural gas liquids;

·       Ourability to continue to obtain new sources of natural gas supply;

·       Theability of key producers to continue to drill and successfully complete andattach new natural gas supplies;

·       Ourability to retain our key customers;

·       Generaleconomic conditions;

·       Theeffects of government regulations and policies; and

·       Otherfinancial, operational and legal risks and uncertainties detailed from time totime in our filings with the SEC.

Cautionary statementsidentifying important factors that could cause actual results to differmaterially from our expectations are set forth in this Annual Report, includingwithout limitation in conjunction with the forward-looking statements that arereferred to above. When considering forward-looking statements, you should keepin mind the risk factors and other cautionary statements set forth in thisAnnual Report under Item 1A “—RiskFactors.”  All forward-lookingstatements included in this Annual Report and all subsequent written or oralforward-looking statements attributable to us or persons acting on our behalfare expressly qualified in their entirety by these cautionary statements. Theforward-looking statements speak only as of the date made, other than asrequired by law, and we undertake no obligation to publicly update or reviseany forward-looking statements, whether as a result of new information, futureevents or otherwise.

**Item 7A.**                Quantitativeand Qualitative Disclosures about Market Risk

Market risk is the risk ofloss arising from adverse changes in market rates and prices. We are exposed tomarket risks, including changes in commodity prices and interest rates. We mayuse financial instruments such as puts, swaps, and other derivatives tomitigate the effects of the identified risks. In general, we attempt to hedgerisks related to the variability of future earnings and cash flows resultingfrom changes in applicable commodity prices or interest rates so that we canmaintain cash flows sufficient to 

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meetdebt service, required capital expenditures, distribution objectives, andsimilar requirements. Our Risk Management Policy prohibits the use ofderivative instruments for speculative purposes.

**Commodity Prices**

*CommodityPrice Risk.**  *NGLand natural gas prices are volatile and are impacted by changes in fundamentalsupply and demand, as well as market uncertainty and a variety of additionalfactors that are beyond our control. Our profitability is affected byprevailing commodity prices primarily as a result of two components of ourbusiness: (1) processing or conditioning at our processing plants orthird-party processing plants and (2) purchasing and selling volumes ofnatural gas at index-related prices.

The processing contracts in our Mid-ContinentOperations segment are predominantly *percentage-of-proceeds*arrangements. Under these arrangements, we generally receive and processnatural gas on behalf of producers and sell the resulting residue gas and NGLvolumes. As payment, we retain an agreed-upon percentage of the sales proceeds,which results in effectively long positions in both natural gas and NGLs. Accordingly,our revenues and gross margins increase as natural gas and NGL prices increase,and revenues and gross margins decrease as natural gas and NGL prices decrease.

The impacts of commodity prices on our Texas GulfCoast Processing segment are more complex, involving the interplay between ourcontractual arrangements and the ability of our Houston Central ProcessingPlant to either *process*or *condition*gas depending on a pricerelationship known as the *processing spread*or *processing margin.*Under thosearrangements, we receive natural gas from producers and third-partytransporters, process or condition the natural gas and sell the resulting NGLsto third parties at market prices. Under a significant number of thesearrangements, we also charge producers and third-party transporters aconditioning fee. These fees provide us additional revenue and compensate usfor the services required to redeliver natural gas that meets downstreampipeline quality specifications. The extraction of NGLs reduces the BTUs of thenatural gas, and to replace these BTUs, we must purchase natural gas at marketprices for return to producers or transporters. When NGL prices are highrelative to natural gas prices, the *processingmargin* is said to be positive, and we operate our Houston CentralProcessing Plant in a manner intended to extract NGLs to the fullest extentpossible. Because of our contractual arrangements, operating our HoustonCentral Processing Plant in maximum recovery mode creates a long position inNGLs and a short position in natural gas. When processing margins are negative,we operate Houston Central Processing Plant in *conditioningmode*to extract the least amount of NGLs needed to meet downstreampipeline hydrocarbon dew point specifications. The ability to condition ratherthan fully process natural gas provides an operational hedge that allows us toreduce our commodity price exposure. Operating our Houston Central ProcessingPlant in conditioning mode creates positions in NGLs and natural gas thatreduce our long or short commodity positions to relatively nominal levels inour Texas Gulf Coast segments.

In order to calculate the sensitivity of our grossmargin to commodity price changes, we adjusted our operating models for actualcommodity prices, plant recovery rates and volumes. Our analysis included theoperations of our newly acquired Mid-Continent Operations segment, beginning onAugust 1, 2005. We have calculated that a 1-cent per gallon changein either direction of NGL prices would have resulted in a corresponding changeof approximately $2.1 million to our gross margin for the year ended December 31,2005. We also calculated that a 10-cent per MMBtu increase in the priceof natural gas would have resulted in approximately a $1.7 milliondecrease to our gross margin, and vice versa, for the year ended December 31,2005. These relationships are not necessarily linear. If processing margins arenegative, we can operate our Houston Central Plant in a conditioning mode sothat additional increases in natural gas prices would have a positive impact toour gross margin.

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*Hedging Activities.**  *We seek to mitigate the price riskof natural gas and NGLs through the use of commodity derivative instruments. Theseactivities are governed by our Risk Management Policy, which allows managementto:

·       purchaseput options on West Texas Intermediate (“WTI”) crude oil;

·       purchaseput or call options and collars (purchase of a put together with the sale of acall) and/or sell fixed for floating swaps on natural gas at Henry Hub, HoustonShip Channel or other highly liquid points relevant to our operations; and

·       purchaseput options and collars (purchase of a put together with the sale of a call)and/or sell fixed for floating swaps on natural gas liquids to which we, or anentity to be acquired by us, has direct price exposure, priced at Mt. Belvieuor Conway.

The policy alsolimits the maturity and notional amounts of our derivatives transactions andrequires that:

·       maturitieswith respect to the purchase of any crude oil or natural gas liquids hedgeinstruments must be limited to three years from the date of the transaction;

·       maturitieswith respect to the purchase of any natural gas hedge instruments must belimited to four years from the date of the transaction;

·       notionalvolume must not exceed (i) 60% of the projected requirements or output, asapplicable, for the hedged period with respect to the purchase of crude oil ornatural gas liquids put options, and (ii) 80% of the projectedrequirements or output, as applicable, for the hedged period with respect tothe purchase of natural gas put or call options; and

·       Theaggregate volumetric exposure associated with swaps, collars and written callsrelating to any product must not exceed 50% of the aggregate hedged positionwith respect to such product.

Our policy of limiting swaps as a percentage of our overallhedge positions is intended to avoid risk associated with potentialfluctuations in output volumes that may result from conditioning elections orother operational circumstances.

Our Risk Management Policy requires derivativetransactions to take place either on the New York Mercantile Exchange (NYMEX)through a clearing member firm or with over-the-counter counterparties withinvestment grade ratings from both Moody’s and Standard & Poor’s withcomplete industry standard contractual documentation. Under this documentation,the payment obligations in connection with our swap transactions are secured bya first priority lien in the collateral securing our senior securedindebtedness that ranks equal in right of payment with liens granted in favorof our senior secured lenders. As long as this first priority lien is ineffect, we will have no obligation to post cash, letters of credit, or otheradditional collateral to secure these hedges at any time even if ourcounterparty’s exposure to our credit increases over the term of the hedge as aresult of higher commodity prices or because there has been a change in ourcreditworthiness.

We will seek, whenever possible, to enter into hedgetransactions that meet or exceed the requirements for effective hedges asoutlined in SFAS No. 133, “*Accountingfor Derivative Instruments and Hedging Activities*.”

*Mid-ContinentOperations Segment.**  *Naturalgas for our Mid-Continent Operations segment is hedged using the CenterPointEast index, the principal index used to price the underlying commodity. Withthe exception of natural gasoline and condensate, NGLs are contractually pricedusing the Conway index, but since there is an extremely limited forward marketfor Conway, we use Mt. Belvieu hedge instruments instead. While this createsthe potential for basis risk, statistical analysis reveals that the two indicesare highly correlated.

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*TexasGulf Coast Pipelines and Processing Segments.***  **With the exception of naturalgasoline and condensate, NGLs are hedged using the Mt. Belvieu index, the sameindex used to price the underlying commodities. We do not hedge natural gas forthe Texas Gulf Coast Pipelines and Processing segments because our natural gasposition is neutral to short due to our contractual arrangements and theability of the Houston Central Processing Plant to switch between full recoveryand conditioning mode. Because of our ability to reject ethane, we have nothedged our ethane production from our Texas Gulf Coast Processing segment.

The following tablesummarizes our commodity hedge portfolio as of December 31, 2005 (allhedges are settled monthly):

**PurchasedCenterPoint East Natural Gas Puts**

| ** ** | ** ** | **Put Strike  (Per MMBtu)** | ** ** | **Put Volumes  MMBtu/d** | ** ** | **                 ** | ** **                                                                                       | ** ** | ** ** |
|------------|------------|---------------------------------------|------------|-------------------------------|------------|------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------|------------|------------|
| 2006       |       | $                                     | 9.90       |                          | 7,750      |                                                                                                       |                  |       |       |   |
| 2007       |       | $                                     | 8.75       |                          | 9,750      |                                                                                                       |                                                                                             |       |       |   |
| 2008       |       | $                                     | 7.75       |                          | 5,000      |                                                                                                       |                                                                                             |       |       |   |
| 2009       |       | $                                     | 6.95       |                          | 5,000      |                                                                                                       |                                                                                             |       |       |   |

 

**PurchasedPurity Ethane Puts and entered into swaps as listed below:**

| ** ** | ** ** | **Put Strike  (per gallon)** | ** ** | **Put Volumes  Bbls/d** | ** ** | **Swap price  (per gallon)** | ** ** | **Swap Volumes  Bbls/d** | ** ** |
|------------|------------|----------------------------------------|------------|------------------------------|------------|----------------------------------------|------------|-------------------------------|------------|
| 2006       |       | $                                      | 0.7125     |                         | 568        |                                   | $          | 0.7315                        |       | 568 |   |
| 2007       |       | $                                      | 0.6365     |                         | 599        |                                   | $          | 0.6525                        |       | 599 |   |
| 2008       |       | $                                      | 0.5700     |                         | 607        |                                   | $          | 0.5650                        |       | 607 |   |

 

**PurchasedTET Propane Puts and entered into swaps as listed below:**

| ** ** | ** ** | **Put Strike  (per gallon)** | ** ** | **Put Volumes  Bbls/d** | ** ** | **Swap price  (per gallon)** | ** ** | **Swap Volumes  Bbls/d** | ** ** |
|------------|------------|----------------------------------------|------------|------------------------------|------------|----------------------------------------|------------|-------------------------------|------------|
| 2006       |       | $                                      | 0.9525     |                         | 2,508      |                                   | $          | 1.0000                        |       | 659 |   |
| 2007       |       | $                                      | 0.8930     |                         | 2,575      |                                   | $          | 0.9375                        |       | 726 |   |
| 2008       |       | $                                      | 0.8360     |                         | 2,594      |                                   | $          | 0.8700                        |       | 745 |   |

 

**PurchasedNon-TET Isobutane Puts and entered into swaps as listed below:**

| ** ** | ** ** | **Put Strike  (per gallon)** | ** ** | **Put Volumes  Bbls/d** | ** ** | **Swap price  (per gallon)** | ** ** | **Swap Volumes  Bbls/d** | ** ** |
|------------|------------|----------------------------------------|------------|------------------------------|------------|----------------------------------------|------------|-------------------------------|------------|
| 2006       |       | $                                      | 1.1425     |                         | 613        |                                   | $          | 1.2050                        |       | 83 |   |
| 2007       |       | $                                      | 1.0675     |                         | 620        |                                   | $          | 1.1250                        |       | 90 |   |
| 2008       |       | $                                      | 0.9900     |                         | 622        |                                   | $          | 1.0450                        |       | 92 |   |

 

**PurchasedNon-TET Normal-Butane Puts and entered into swaps as listed below:**

| ** ** | ** ** | **Put Strike  (per gallon)** | ** ** | **Put Volumes  Bbls/d** | ** ** | **Swap price  (per gallon)** | ** ** | **Swap Volumes  Bbls/d** | ** ** |
|------------|------------|----------------------------------------|------------|------------------------------|------------|----------------------------------------|------------|-------------------------------|------------|
| 2006       |       | $                                      | 1.1400     |                         | 780        |                                   | $          | 1.2000                        |       | 241 |   |
| 2007       |       | $                                      | 1.0650     |                         | 803        |                                   | $          | 1.1200                        |       | 264 |   |
| 2008       |       | $                                      | 0.9875     |                         | 810        |                                   | $          | 1.0400                        |       | 271 |   |

 

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**Purchased WTI Crude Oil Puts as listed below:(1)**

| ** ** | ** ** | **Put Strike  (per barrel)** | ** ** | **Put Volumes  Bbls/d** | ** ** | ** ** | ** ** | ** ** | ** ** |
|------------|------------|----------------------------------------|------------|------------------------------|------------|------------|------------|------------|------------|
| 2006       |       | $                                      | 48.00      |                         | 2,000      |       |       |       |       |   |
| 2007       |       | $                                      | 48.00      |                         | 2,000      |       |       |       |       |   |

----

(1)          WTICrude Oil Puts were purchased in July 2005. Volumes are based on a 30-daymonth.

**Interest Rates**

Our interest rate exposure results from variable rateborrowings under our debt agreements. As of the quarter ended December 31,2005, we were exposed to changes in interest rates as a result of theindebtedness outstanding under our credit facilities of $398.0 million, whichhad an average floating interest rate of 7.6%. A 1% increase in interest rateson this amount of debt would result in an increase in interest expense and acorresponding decrease in net income of approximately $4.0 million annually.

We manage a portion of ourinterest rate exposure by utilizing interest rate swaps, which allow us toconvert a portion of variable rate debt into fixed rate debt. These activitiesare governed by our Risk Management Policy, which limits the maturity andnotional amounts of our interest rate swaps as well as restricts counterpartiesto certain lenders under our most senior credit agreement. In October 2005,we entered into two interest rate swap agreements with an aggregate notionalamount of $50 million in which we exchanged the payment of variable rateinterest on a portion of the principal outstanding under the Credit Facilityfor fixed rate interest. We have designated these two interest rate swaps ascash flow hedges under SFAS No. 133, “*Accountingfor Derivative Instruments and Hedging Activities*” (as amended andinterpreted). Under each swap agreement, we pay the counterparties the fixedinterest rate of approximately 4.7% monthly and receive in return a variableinterest rate based on one-month LIBOR rates. The interest rate swaps cover theperiod from October 2005 through July 2010 and the settlement amountswill be recognized to earnings as either an increase or a decrease in interestexpense.

**Risk ManagementOversight**

Our Risk Management Committeeis responsible for our compliance with our Risk Management Policy and iscomprised of senior level executives in the operations, finance and legaldepartments. The Audit Committee of our Board of Directors monitors theimplementation of the policy and we have engaged an independent firm to provideadditional oversight.

**Credit Risk andSignificant Customers**

We are diligent inattempting to ensure that we provide credit to only credit-worthy customers. However,our purchase and resale of natural gas exposes us to significant credit risk,as the margin on any sale is generally a very small percentage of the totalsale price. Therefore, a credit loss could be very large relative to ouroverall profitability. For the year ended December 31, 2005, Kinder MorganTexas Pipeline, L.P. (26%), Oneok Hydrocarbons, L.P. (14%) and a subsidiary ofDow Chemical (12%) collectively accounted for approximately 52% of our revenue.We are exposed to market risks, including changes in commodity prices andinterest rates. We may use financial instruments such as puts, swaps, optionsand other financial instruments with similar characteristics to mitigate therisks of certain identifiable and anticipated transactions consistent with ourRisk Management Policy. In general, the type of risks we attempt to hedge arethose related to the variability of future earnings, fair values of certaindebt instruments and cash flows resulting from changes in applicable commodityprices or interest rates. As a matter of policy, we do not use financialinstruments for speculative (or “trading”) purposes.

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**Item 8.**                        FinancialStatements and Supplementary Data

The Report of IndependentRegistered Public Accounting Firm, Consolidated Financial Statements andsupplementary financial data required for this Item are set forth on pages F-1through F-58 of this Annual Report and are incorporated herein by reference.

**Item 9.**                        Changesin and Disagreements With Accountants on Accounting and Financial Disclosure

None.

**Item 9A.**                Controlsand Procedures

We carried out an evaluation under the supervision andwith the participation of our management, including our Chief Executive Officerand Chief Financial Officer, of the effectiveness of our disclosure controlsand procedures as of the end of the period covered by this Annual Report. Basedon this evaluation, our Chief Executive Officer and Chief Financial Officerconcluded that our disclosure controls and procedures were effective to providereasonable assurance that information required to be disclosed in our reportsfiled or submitted under the Exchange Act is recorded, processed, summarizedand reported timely.

There have been no changesin our internal control over financial reporting (as defined in Rule 13a-15(f) underthe Exchange Act) that occurred during the last quarter that have materiallyaffected or are reasonably likely to materially affect our internal controlover financial reporting.

*Management’s AnnualReport on Internal Control over Financial Reporting*

Our management isresponsible for establishing and maintaining adequate internal control overfinancial reporting as defined in Rules 13a-15(f) and 15d-15(f) underthe Exchange Act. Our internal control over financial reporting is designed toprovide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles. Our internal control overfinancial reporting includes those policies and procedures that:

(i)            pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect our transactions and dispositions of our assets;

(ii)        provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that our receipts and expenditures are being made only inaccordance with authorizations of our management and directors; and

(iii)    provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use ordisposition our assets that could have a material effect on the financialstatements.

Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements. Also,projections of any evaluation of effectiveness to future periods are subject tothe risk that controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

Our management assessed the effectiveness of ourinternal control over financial reporting as of December 31, 2005. Inmaking this assessment, management used the criteria set forth by the Committeeof Sponsoring Organizations of the Treadway Commission (“COSO”) in InternalControl-Integrated Framework.

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Based on our assessmentand those criteria, management believes that we maintained effective internalcontrol over financial reporting as of December 31, 2005.

*Internal ControlOver Financial Reporting and the ScissorTail Energy Acquisition*

On August 1, 2005, we completed the ScissorTailAcquisition, which met the criteria of being a significant acquisition for us. Foradditional information regarding the acquisition, please read Item 1 “Business”of this Annual Report. As of December 31, 2005, ScissorTail representedapproximately 72% of our total consolidated assets. In addition, theseoperations accounted for 78% and 27% of our consolidated net income andrevenue, respectively, for the year ended December 31, 2005.

On June 22, 2004, the Office of the ChiefAccountant of the SEC issued guidance regarding the reporting of internalcontrol over financial reporting in connection with a major acquisition. On October 6,2004, the SEC revised its guidance to include expectations of quarterlyreporting updates of new internal control and the status of the controlregarding any exempted businesses.

We have excludedScissorTail from the scope of our Sarbanes-Oxley Section 404 report oninternal controls over financial reporting for the year ended December 31,2005. A summary of the reasons for exclusion follow:

·       ScissorTailutilized a financial accounting (i.e. a general ledger) computer system that isdifferent from that used by us. For practical reasons, ScissorTail remained onthese systems through December 31, 2005. We plan to convert theScissorTail financial systems to the systems that we utilize in 2006.  As a result, we believe that reporting on thecontrols relating to the computer system used by ScissorTail during 2005 wouldnot be useful to our investors since these systems will be discontinued.

·       We are in the process ofimplementing our internal control structure over the operations of ScissorTail.Due to the magnitude of the businesses, we expect that this effort will becompleted in 2006. The assessment and documentation of internal controlsrequires a complete review of controls operating in a stable and effectiveenvironment.

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**MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLOVER FINANCIAL REPORTINGAS OF DECEMBER 31, 2005**

The management of Copano Energy, L.L.C. and itsconsolidated subsidiaries, including the Chief Executive Officer and the ChiefFinancial Officer, is responsible for establishing and maintaining adequateinternal control over financial reporting, as defined in Rules 13a-15(f) and15d-15(f) of the Exchange Act. Our internal control system wasdesigned to provide reasonable assurance to our management and Board of Directorsregarding the preparation and fair presentation of published financial statements.However, our management does not expect that our disclosure controls andprocedures or internal control over financial reporting will prevent all errorand all fraud. A control system, no matter how well conceived and operated, canprovide only a reasonable, not absolute, assurance that the objectives of thecontrol system are met.

Our management assessed the effectiveness of ourinternal control over financial reporting as of December 31, 2005. Inmaking this assessment, it used the criteria set forth by COSO in InternalControl—Integrated Framework. This assessment included design effectiveness andoperating effectiveness of internal control over financial reporting as well asthe safeguarding of our assets. Based on our assessment, we believe that, as ofDecember 31, 2005, our internal control over financial reporting iseffective based on those criteria excluding ScissorTail. ScissorTail wasacquired on August 1, 2005 and the associated financial statements reflecttotal assets and revenues constituting approximately 72% and 27%, respectively,of the related consolidated financial statement amounts as of and for the yearended December 31, 2005. An explanation of this exclusion and the reasonsfor excluding ScissorTail is provided in Item 9A of this Annual Report.

Our management’s assessment of the effectiveness ofour internal control over financial reporting as of December 31, 2005 hasbeen audited by Deloitte & Touche LLP, an independent registeredpublic accounting firm, as stated in their report which is included hereinunder Item 9A of this Annual Report.

Our Audit Committee is composed of directors who arenot officers or employees of our company. It meets regularly with members ofmanagement, the internal auditors and the representatives of the independentregistered public accounting firm to discuss the adequacy of our internalcontrol over financial reporting, financial statements and the nature, extentand results of the audit effort. Management reviews with the Audit Committeeall of our significant accounting policies and assumptions affecting theresults of operations. Both the independent registered public accounting firmand internal auditors have direct access to the Audit Committee without thepresence of management.

Pursuant to the requirementsof Rules 13a-15(f) and 15d-15(f) of the SecuritiesExchange Act of 1934, as amended, this Annual Report on Internal Control OverFinancial Reporting has been signed below by the following persons on behalf ofthe registrant and in the capacities indicated below on March 16, 2006.

| /s/  JOHN R. ECKEL, JR.            |   | /s/ MATTHEW J.  ASSIFF    |
|-----------------------------------------|--------|---------------------------|
| Chairman of the  Board of Directors and |   | Senior Vice President and |
| Chief Executive  Officer                |   | Chief Financial Officer   |

 

Our independent auditorshave issued an attestation report on management’s assessment of our internalcontrol over financial reporting. That report appears below.

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

To the Board of Directors and Unitholders of CopanoEnergy, L.L.C.Houston, Texas

We have audited management’s assessment, included inthe accompanying Management’s Annual Report on Internal Control over FinancialReporting, that Copano Energy, L.L.C. and subsidiaries (the “Company”)maintained effective internal control over financial reporting as of December 31,2005, based on criteria established in Internal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.As described in Management’s Annual Report on Internal Control Over FinancialReporting, management excluded from their assessment the internal control overfinancial reporting at ScissorTail Energy, LLC, which was acquired on August 1,2005 and whose financial statements constitute 72 percent of total assets and27 percent of revenue of the consolidated financial statement amounts as of andfor the year ended December 31, 2005. Accordingly, our audit did notinclude the internal control over financial reporting at ScissorTail Energy,LLC. The Company’s management is responsible for maintaining effective internalcontrol over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting. Our responsibility is to express anopinion on management’s assessment and an opinion on the effectiveness of theCompany’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting wasmaintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinions.

A company’s internal control over financial reportingis a process designed by, or under the supervision of, the company’s principalexecutive and principal financial officers, or persons performing similarfunctions, and effected by the company’s board of directors, management, andother personnel to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being madeonly in accordance with authorizations of management and directors of thecompany; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internalcontrol over financial reporting, including the possibility of collusion orimproper management override of controls, material misstatements due to erroror fraud may not be prevented or detected on a timely basis. Also, projectionsof any evaluation of the effectiveness of the internal control over financialreporting to future periods are subject to the risk that the controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

In our opinion,management’s assessment that the Company maintained effective internal controlover financial reporting as of December 31, 2005, is fairly stated, in allmaterial respects, based on the criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission. Also in our opinion, the Company maintained, in all material 

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respects,effective internal control over financial reporting as of December 31,2005, based on the criteria established in Internal Control—IntegratedFramework issued by the Committee of Sponsoring Organizations of the TreadwayCommission.

We havealso audited, in accordance with the standards of the Public Company AccountingOversight Board (United States), the consolidated financial statements as ofand for the year ended December 31, 2005 of the Company and our reportdated March 16, 2006, expressed an unqualified opinion on those financialstatements, and included an explanatory paragraph relating to the requiredadoption of a new accounting principal for accounting for conditional assetretirement obligations.

| /s/ DELOITTE & TOUCHE LLP |   |   |
|------------------------------------|--------|--------|

 

Houston, TexasMarch 16, 2006

**Item 9B.**               OtherInformation

On March 2, 2005, we filed a Current Report on Form 8-Kannouncing that our Board of Directors had approved the Copano Energy, L.L.C.Management Incentive Compensation Plan, or the Plan, upon the recommendation ofthe Compensation Committee of the Board. In addition, we announced that theCompensation Committee had adopted the 2005 Administrative Guidelines for the Plan,which designated plan participants and target awards for 2005. In April 2005,Ron W. Bopp was elected as our Senior Vice President, Corporate Development andin May 2005, Wayne Harrison was elected as our Vice President and ChiefInformation Officer. In connection with their election as officers, theCompensation Committee designated Mr. Bopp and Mr. Harrison asparticipants in the Plan for 2005 and established target awards for them of 50%and 30%, respectively.

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**PART III**

**Item 10.**                 Directorsand Executive Officers of the Registrant

The information requiredby Item 10 is incorporated herein by reference to the applicableinformation in our Proxy Statement for our 2006 Annual Meeting of Unitholdersset forth under the caption “Proposal One—Election of Directors,” “The Board ofDirectors and its Committees” and “Executive Officers” to be filed with the SECnot later than 120 days after the close of the fiscal year.

**Item 11.**                 ExecutiveCompensation

The information requiredby Item 11, including information concerning grants under our equitycompensation plan for directors and employees, is incorporated herein byreference to the applicable information in our Proxy Statement for our 2006Annual Meeting of Unitholders set forth under the captions “The Board ofDirectors and its Committees—Director Compensation” and “Executive Compensation”to be filed with the SEC not later than 120 days after the close of the fiscalyear.

**Item 12.**                 SecurityOwnership of Certain Beneficial Owners and Management and Related UnitholderMatters

The information requiredby Item 12, including information concerning ownership and options underour equity compensation plan for directors and employees, is incorporatedherein by reference to our Proxy Statement for our 2006 Annual Meeting ofUnitholders set forth under the captions “Security Ownership of CertainBeneficial Owners and Management” and “Executive Compensation” to be filed withthe SEC not later than 120 days after the close of the fiscal year.

**Item 13.**                 CertainRelationships and Related Parties

The information requiredby Item 13 is incorporated herein by reference to the applicableinformation in our Proxy Statement for our 2006 Annual Meeting of Unitholdersset forth under the caption “Certain Relationships and Related Transactions” tobe filed with the SEC not later than 120 days after the close of the fiscalyear.

**Item 14.**                 PrincipalAccountant Fees and Services

The information required by Item 14 isincorporated herein by reference to the applicable information in our ProxyStatement for our 2006 Annual Meeting of Unitholders set forth under thecaption “Proposal Two—Ratification of Independent Public Accountants” to befiled with the SEC not later than 120 days after the close of the fiscal year.

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**PART IV**

**Item 15.**                 Exhibitsand Financial Statement Schedules.

**(a)(1) and (2) Financial Statements**

The consolidated financialstatements of Copano Energy, L.L.C. are listed on the Index to FinancialStatements to this Annual Report beginning on page F-1.

**(a)(3) Exhibits**

Thefollowing documents are filed as a part of this Annual Report or incorporatedby reference.

| Number | ** ** | **Description**                                                                                                                                                                                                                                                                                                               |
|--------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1    |       | Certificate of Formation  of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated  by reference to Exhibit 3.1 to Registration Statement on Form S-1  filed July 30, 2004).                                                                                                                |
| 3.2    |       | Certificate of  Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now  Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to  Registration Statement on Form S-1 filed July 30, 2004).                                                                                    |
| 3.3    |       | Second Amended  and Restated Limited Liability Company Agreement of Copano Energy, L.L.C.  (incorporated by reference to Exhibit 3.3 to Post-Effective Amendment  No. 1 to Registration Statement on Form S-1/A filed  December 15, 2004).                                                                |
| 3.4    |       | Amendment  No. 1 to Second Amended and Restated Limited Liability Company Agreement  of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.4 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                         |
| 3.5    |       | Amendment  No. 2 to Second Amended and Restated Limited Liability Company Agreement  of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.5 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                         |
| 4.1    |       | Indenture dated  as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy  Finance Corporation, the Guarantors parties thereto and U.S. Bank National  Association, as trustee (incorporated by reference to Exhibit 4.1 to  Current Report on Form 8-K filed February 8, 2006).                |
| 4.2    |       | Rule 144A  Global Note representing $224,500,000 principal amount of 8.125% Senior Notes  due 2016 (incorporated by reference to Exhibit 4.2 to Current Report on  Form 8-K filed February 8, 2006).                                                                                                      |
| 4.3    |       | Regulation S  Global Note representing $500,000 principal amount of 8.125% Senior Notes due  2016 (incorporated by reference to Exhibit 4.3 to Current Report on  Form 8-K filed February 8, 2006).                                                                                                       |
| 4.4    |       | Registration  Rights Agreement dated as of February 7, 2006, among Copano Energy,  L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and  the Initial Purchasers named therein (incorporated by reference to  Exhibit 4.4 to Current Report on Form 8-K filed  February 8, 2006). |

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| 4.5  |   | Class B Unit and  Common Unit Purchase Agreement dated as of June 17, 2005 by and among  Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH Energy  MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise Energy Infrastructure  Corporation, Tortoise Energy Capital Corporation, Goldman, Sachs &  Co., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund,  Alerian Opportunity Partners LP, Alerian Capital Partners LP, Strome  HedgeCap, LP, Strome Alpha, LP and Strome Family Foundation (incorporated by  reference to Exhibit 10.27 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                    |
|------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 4.6  |   | Registration  Rights Agreement made and entered into as of August 1, 2005, by and  among Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH  Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise Energy Infrastructure  Corporation, Tortoise Energy Capital Corporation, Goldman, Sachs &  Co., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund,  Alerian Opportunity Partners LP, Alerian Capital Partners LP, Strome MLP  Fund, L.P., Strome Alpha, LP and Strome Family Foundation (incorporated by  reference to Exhibit 10.28 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                       |
| 4.7* |   | Common Unit  Purchase Agreement dated as of December 29, 2005, by and among Copano  Energy, L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and Royal  Bank of Canada.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 4.8* |   | Registration  Rights Agreement dated as of December 29, 2005, by and among Copano  Energy, L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and Royal  Bank of Canada.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.1 |   | Amended and  Restated Credit Agreement dated February 13, 2004 among Copano Pipelines  Group, L.L.C., Copano Field Services/Copano Bay, L.P., Copano Field  Services/Agua Dulce, L.P., Copano Field Services/South Texas, L.P., Copano  Field Services/Upper Gulf Coast, L.P., Copano Field Services/Live Oak, L.P.,  Copano Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas,  L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville,  L.P. and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and  Fleet National Bank and the other Lenders named therein (incorporated by  reference to Exhibit 10.1 to Amendment No. 2 to Registration  Statement on Form S-1/A filed October 12, 2004).                         |
| 10.2 |   | First Amendment  to Amended and Restated Credit Agreement dated as of March 15, 2004,  among Copano Pipelines Group, L.L.C., Copano Field Services/Copano Bay, L.P.,  Copano Field Services/Agua Dulce, L.P., Copano Field Services/South Texas,  L.P., Copano Field Services/Upper Gulf Coast, L.P., Copano Field Services/Live  Oak, L.P., Copano Field Services/Central Gulf Coast, L.P., Copano  Pipelines/South Texas, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano  Pipelines/Hebbronville, L.P. and Copano Energy Services/Upper Gulf Coast,  L.P., as the Borrowers, and Fleet National Bank and the other Lenders named  therein (incorporated by reference to Exhibit 10.2 to Amendment  No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004). |

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| 10.3       |   | Second Amendment to  Amended and Restated Credit Agreement dated as of November 15, 2004,  among Copano Pipelines Group, L.L.C., Copano Field Services/ Copano Bay,  L.P., Copano Field Services/Agua Dulce, L.P., Copano Field Services/ South  Texas, L.P., Copano Field Services/Upper Gulf Coast, L.P., Copano Field  Services/Live Oak, L.P., Copano Field Services/Central Gulf Coast, L.P.,  Copano Pipelines/South Texas, L.P., Copano Pipelines/Upper Gulf Coast, L.P.,  Copano Pipelines/Hebbronville, L.P., and Copano Energy Services/Upper Gulf  Coast, L.P., as the Borrowers, and Fleet National Bank and the other Lenders  named therein (incorporated by reference to Exhibit 10.3 to  Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A  filed December 15, 2004). |
|------------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.4       |   | Credit Agreement  dated as of November 15, 2004, by and among Copano Houston Central,  L.L.C., Copano Processing, L.P. and Copano NGL Services, L.P. as the  Borrowers and Comerica Bank as the Lender (incorporated by reference to  Exhibit 10.4 to Post-Effective Amendment No. 1 to Registration  Statement on Form S-1/A filed December 15, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 10.5       |   | Form of  Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to  Exhibit 10.5 to Amendment No. 3 to Registration Statement on  Form S-1/A filed October 26, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.6       |   | Stakeholders’  Agreement dated July 30, 2004, by and among Copano Energy, L.L.C.,  Copano Partners, L.P., R. Bruce Northcutt, Matthew J. Assiff, EnCap Energy  Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP  Energy Partners, L.P., CEH Holdco, Inc., CEH Holdco II, Inc., DLJ  Merchant Banking Partners III, L.P., DLJ Offshore Partners III, C.V., DLJ  Offshore Partner III-1, C.V., DLJ Offshore Partners III-2, C.V.,  DLJ Merchant Banking III, Inc., DLJ MB Partners III GmbH & Co,  KG, Millennium Partners II, L.P. and MBP III Plan Investors, L.P.  (incorporated by reference to Exhibit 10.6 to Registration Statement on  Form S-1 filed July 30, 2004).                                                                                 |
| 10.7† |   | Amended and  Restated Gas Processing Contract dated as of January 1, 2004, between  Kinder Morgan Texas Pipeline, L.P. and Copano Processing, L.P. (incorporated  by reference to Exhibit 10.7 to Amendment No. 6 to Registration  Statement on Form S-1/A filed November 5, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 10.8       |   | Employment  Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the  Copano Controlling Entities, dated April 9, 2003 (incorporated by  reference to Exhibit 10.8 to Amendment No. 2 to Registration  Statement on Form S-1/A filed October 12, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.9       |   | First Amendment  to Employment Agreement between Copano/Operations, Inc., R. Bruce  Northcutt and the Copano Controlling Entities, dated July 30, 2004  (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to  Registration Statement on Form S-1/A filed October 12, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 10.10      |   | Assignment and  Assumption Agreement between Copano/Operations, Inc. and CPNO Services,  L.P. effective January 1, 2005 with respect to Employment Agreement  between Copano/Operations, Inc., R. Bruce Northcutt and the Copano  Controlling Entities, as amended (incorporated by reference to  Exhibit 10.10 to Annual Report on Form 10-K filed March 31,  2005).                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.11      |   | Second Amendment  to Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and  the Copano Controlling Entities, effective March 1, 2005 (incorporated  by reference to Exhibit 10.10 to Annual Report on Form 10-K  filed March 31, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 10.12      |   | Employment  Agreement between Copano/Operations, Inc. and James J. Gibson, III,  dated as of October 1, 2004 (incorporated by reference to  Exhibit 10.10 to Amendment No. 4 to Registration Statement on  Form S-1/A filed November 2, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

93

----

 

| 10.13 |   | Assignment and  Assumption Agreement between Copano/Operations, Inc. and CPNO Services,  L.P. effective January 1, 2005 with respect to Employment Agreement  between Copano/Operations, Inc. and James J. Gibson, III  (incorporated by reference to Exhibit 10.10 to Annual Report on  Form 10-K filed March 31, 2005).                                                                                                                                                                                                   |
|-------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.14 |   | First Amendment  to Employment Agreement between CPNO Services, L.P. and James J.  Gibson, III, effective March 1, 2005 (incorporated by reference to  Exhibit 10.10 to Annual Report on Form 10-K filed  March 31, 2005).                                                                                                                                                                                                                                                                                                            |
| 10.15 |   | Lease Agreement  dated as of October 17, 2000, between Plow Realty Company of Texas and  Texas Gas Plants, L.P. (incorporated by reference to Exhibit 10.13 to  Amendment No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                                                                                                                                     |
| 10.16 |   | Lease Agreement  dated as of December 3, 1964, between The Plow Realty Company of Texas  and Shell Oil Company (incorporated by reference to Exhibit 10.14 to  Amendment No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                                                                                                                                      |
| 10.17 |   | Lease Agreement  dated as of January 1, 1944, between The Plow Realty Company of Texas  and Shell Oil Company, Incorporated (incorporated by reference to  Exhibit 10.15 to Amendment No. 2 to Registration Statement on  Form S-1/A filed October 12, 2004).                                                                                                                                                                                                                                                                         |
| 10.18 |   | Form of  Restricted Unit Grant (Directors) (incorporated by reference to  Exhibit 10.1 to Current Report on Form 8-K filed  December 15, 2004).                                                                                                                                                                                                                                                                                                                                                                                            |
| 10.19 |   | Form of  Grant of Options (incorporated by reference to Exhibit 10.17 to  Quarterly Report on Form 10-Q filed December 21, 2004).                                                                                                                                                                                                                                                                                                                                                                                                          |
| 10.20 |   | Form of  Restricted Unit Grant (Employees) (incorporated by reference to  Exhibit 4.4 to Registration Statement on Form S-8 filed  February 11, 2005).                                                                                                                                                                                                                                                                                                                                                                                     |
| 10.21 |   | Form of Unit  Option Grant under the Copano Energy, L.L.C. Long-Term Incentive Plan.  (incorporated by reference to Exhibit 4.5 to Registration Statement on  Form S-8 filed February 11, 2005).                                                                                                                                                                                                                                                                                                                                           |
| 10.22 |   | Administrative  and Operating Services Agreement dated November 15, 2004, among  Copano/Operations, Inc. and Copano Energy, L.L.C., and the Copano  Operating Subsidiaries listed therein (incorporated by reference to  Exhibit 3.4 to Post-Effective Amendment No. 1 to Registration  Statement on Form S-1/A filed December 15, 2004).                                                                                                                                                                                        |
| 10.23 |   | Copano Energy,  L.L.C. Management Incentive Compensation Plan (incorporated by reference to  Exhibit 10.1 to Current Report on Form 8-K filed  March 2, 2005).                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.24 |   | 2005  Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive  Compensation Plan (incorporated by reference to Exhibit 10.2 to Current  Report on Form 8-K filed March 2, 2005).                                                                                                                                                                                                                                                                                                                                           |
| 10.25 |   | Unitholder Voting  Agreement dated as of August 1, 2005 by and among Copano Partners Trust,  MBP III AIV, L.P., MBP Onapoc Holdings LLC, R. Bruce Northcutt and Matthew J.  Assiff (incorporated by reference to Exhibit 10.29 to Quarterly Report  on Form 10-Q filed August 15, 2005).                                                                                                                                                                                                                                                   |
| 10.26 |   | Credit Agreement  dated as of August 1, 2005 among Copano Energy, L.L.C., as the Borrower,  Bank of America, N.A., as Administrative Agent and L/C Issuer, Comerica Bank  and U.S. Bank National Association, as Co-Syndication Agents, Bank of  Scotland and Fortis Capital Corp., as Co-Documentation Agents and The Other  Lenders Party Hereto and Banc of America Securities LLC, as Sole Lead  Arranger and Sole Book Manager (incorporated by reference to  Exhibit 10.30 to Quarterly Report on Form 10-Q filed  August 15, 2005). |

94

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| 10.27 |   | Bridge Loan Agreement dated as of August 1,  2005 among Copano Energy, L.L.C., as the Borrower, Banc of America Bridge  LLC, as Administrative Agent and The Other Lenders Party Hereto and Banc of  America Securities LLC, as Sole Lead Arranger and Sole Book Manager  (incorporated by reference to Exhibit 10.31 to Quarterly Report on  Form 10-Q filed August 15, 2005). |
|-------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.28 |   | Employment  Agreement between CPNO Services, L.P. and John A. Raber dated as of  August 1, 2005 (incorporated by reference to Exhibit 10.32 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                           |
| 10.29 |   | Employment  Agreement between ScissorTail Energy, L.L.C. and Bruce Roderick dated as of  August 1, 2005 (incorporated by reference to Exhibit 10.33 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                   |
| 10.30 |   | Employment  Agreement between ScissorTail Energy, L.L.C. and Sharon Robinson dated as of  August 1, 2005 (incorporated by reference to Exhibit 10.34 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                  |
| 10.31 |   | Employment  Agreement between ScissorTail Energy, L.L.C. and Thomas Coleman dated as of  August 1, 2005 (incorporated by reference to Exhibit 10.35 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                   |
| 10.32 |   | Employment  Agreement between ScissorTail Energy, L.L.C. and Lee E. Fiegener dated as of  August 1, 2005 (incorporated by reference to Exhibit 10.36 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                  |
| 10.33 |   | Form of Unit  Option Grant under the Copano Energy, L.L.C. Long-Term Incentive Plan  (ScissorTail Energy, LLC Officers) (incorporated by reference to  Exhibit 10.37 to Quarterly Report on Form 10-Q filed  August 15, 2005).                                                                                                                                                  |
| 10.34 |   | Form of  Restricted Unit Grant under the Copano Energy, L.L.C. Long-Term Incentive  Plan (ScissorTail Energy, LLC Officers) (incorporated by reference to  Exhibit 10.38 to Quarterly Report on Form 10-Q filed  August 15, 2005).                                                                                                                                              |
| 10.35 |   | Form of  Indemnification Agreement (incorporated by reference to Exhibit 10.1 to  Current Report on Form 8-K filed November 2, 2005).                                                                                                                                                                                                                                           |
| 10.36 |   | First Amendment  to Copano Energy, L.L.C. Long-Term Incentive Plan dated October 27, 2005  (incorporated by reference to Exhibit 10.2 to Current Report on  Form 8-K filed November 2, 2005).                                                                                                                                                                                   |
| 10.37 |   | Purchase  Agreement dated as of January 31, 2006, among Copano Energy, L.L.C.,  Copano Energy Finance Corporation, the Guarantors parties thereto and the  Initial Purchasers named therein (incorporated by reference to  Exhibit 10.1 to Current Report on Form 8-K filed  February 8, 2006).                                                                                 |
| 10.38 |   | 2006  Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive  Compensation Plan (incorporated by reference to Exhibit 10.1 to Current  Report on Form 8-K filed February 21, 2006).                                                                                                                                                                            |
| 21.1  |   | List of  Subsidiaries.                                                                                                                                                                                                                                                                                                                                                                              |
| 23.1* |   | Consent of  Deloitte & Touche LLP.                                                                                                                                                                                                                                                                                                                                                         |
| 31.1* |   | Sarbanes-Oxley  Section 302 certification of John R. Eckel, Jr. (Chief Executive  Officer) for Copano Energy, L.L.C.                                                                                                                                                                                                                                                                      |
| 31.2* |   | Sarbanes-Oxley  Section 302 certification of Matthew J. Assiff (Chief Financial Officer)  for Copano Energy, L.L.C.                                                                                                                                                                                                                                                                            |

95

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| 32.1* |   | Sarbanes-Oxley  Section 906 certification of John R. Eckel, Jr. (Chief Executive  Officer) for Copano Energy, L.L.C. |
|-------|--------|--------------------------------------------------------------------------------------------------------------------------------|
| 32.2* |   | Sarbanes-Oxley  Section 906 certification of Matthew J. Assiff (Chief Financial Officer)  for Copano Energy, L.L.C.       |

----

*                    Filedherewith.

†                    Portionsof this exhibit have been omitted pursuant to a request for confidentialtreatment.

**(b) Exhibits**

See Item 15(a)(3) above.

96

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this Annual Report to be signed onits behalf by the undersigned, thereunto duly authorized, in the City ofHouston, State of Texas, on the 16th day of March 2006.

|   |   | COPANO ENERGY, L.L.C. |
|--------|--------|-----------------------|
|   |   | By:                   |   | /s/ JOHN R. ECKEL, JR. |
|   |   |                  |   | John R. Eckel, Jr. |
|   |   |                  |   | Chairman of the Board of Directors and |
|   |   |                  |   | Chief Executive Officer |
|   |   | By:                   |   | /s/ MATTHEW J. ASSIFF |
|   |   |                  |   | Matthew J. Assiff |
|   |   |                  |   | Senior Vice President and Chief Financial Officer |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this Annual Reporthas been signed below on the dates indicated by the following persons on behalfof the Registrant and in the capacities indicated.

|                                | **Signature** | ** **                                             | ** ** |                     | **Title** | ** ** | ** ** |  | **Date** | ** ** |
|--------------------------------|---------------|--------------------------------------------------------|------------|---------------------|-----------|------------|------------|--|----------|------------|
| /s/  JOHN R. ECKEL, JR.   |          | Chairman of the  Board of Directors and                |       | March 16, 2006 |
| John R.  Eckel, Jr.       |          | Chief Executive Officer  (Principal Executive Officer) |       |                |
| /s/  MATTHEW J. ASSIFF         |          | Senior Vice  President and Chief Financial             |       | March 16, 2006 |
| Matthew J. Assiff              |          | Officer  (Principal Financial Officer)                 |       |                |
| /s/  LARI PARADEE              |          | Vice President  and Controller (Principal              |       | March 16, 2006 |
| Lari Paradee                   |          | Accounting  Officer)                                   |       |                |
| /s/  ROBERT L. CABES, JR. |          | Director                                               |       | March 16, 2006 |
| Robert L.  Cabes, Jr.     |          |                                                   |       |                |
| /s/  JAMES G. CRUMP            |          | Director                                               |       | March 16, 2006 |
| James G. Crump                 |          |                                                   |       |                |
| /s/  ERNIE L. DANNER           |          | Director                                               |       | March 16, 2006 |
| Ernie L. Danner                |          |                                                   |       |                |
| /s/ MICHAEL L. JOHNSON    |          | Director                                               |       | March 16, 2006 |
| Michael L.  Johnson            |          |                                                   |       |                |

97

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| /s/ SCOTT  A. GRIFFITHS |   | Director |   | March 16,  2006 |
|------------------------------|--------|----------|--------|----------------------|
| Scott A.  Griffiths          |   |     |   |                 |
| /s/ T. WILLIAM PORTER   |   | Director |   | March 16, 2006  |
| T. William Porter            |   |     |   |                 |
| /s/ WILLIAM L. THACKER  |   | Director |   | March 16, 2006  |
| William L.  Thacker          |   |     |   |                 |

 

98

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**COPANOENERGY, L.L.C.INDEX TO FINANCIAL STATEMENTS**

| **Copano Energy, L.L.C. and Subsidiaries Consolidated Financial  Statements:**                                                              |   |   |   |
|---------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|
| Report of Independent Registered Public Accounting  Firm                                                                                    |   | F-2    |   |
| Consolidated Balance Sheets as of December 31,  2005 and 2004                                                                          |   | F-3    |   |
| Consolidated Statements of Operations for the years  ended December 31, 2005, 2004 and 2003                                            |   | F-4    |   |
| Consolidated Statements of Cash Flows for the years  ended December 31, 2005, 2004 and 2003                                            |   | F-5    |   |
| Consolidated Statements of Members’ Capital and Comprehensive  Income (Loss) for the years ended December 31, 2005, 2004 and 2003 |   | F-6    |   |
| Notes to  Consolidated Financial Statements                                                                                                 |   | F-7    |   |
| **Webb/Duval  Gatherers Financial Statements:**                                                                                             |   |   |   |
| Report of Independent Registered Public Accounting  Firm                                                                                    |   | F-46   |   |
| Balance Sheets  as of December 31, 2005 (unaudited) and 2004                                                                           |   | F-47   |   |
| Statements of Operations for the years ended  December 31, 2005 (unaudited), 2004 and 2003 (unaudited)                            |   | F-48   |   |
| Statements of Cash Flows for the years ended  December 31, 2005 (unaudited), 2004 and 2003 (unaudited)                            |   | F-49   |   |
| Statements of Partners’ Capital for the years ended  December 31, 2005 (unaudited), 2004 and 2003 (unaudited)                     |   | F-50   |   |
| Notes to Financial Statements                                                                                                               |   | F-51   |   |

 

F-1

----

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

Tothe Board of Directors and Unitholders of Copano Energy, L.L.C. andSubsidiaries:

Houston, Texas

We have audited the accompanying consolidated balancesheets of Copano Energy, L.L.C. and subsidiaries (the “Company”) as of December 31,2005 and 2004, and the related consolidated statements of operations, members’capital and comprehensive income (loss), and cash flows for each of the threeyears in the period ended December 31, 2005. These financial statementsare the responsibility of the Company’s management. Our responsibility is toexpress an opinion on these financial statements based on our audits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statementspresent fairly, in all material respects, the financial position of CopanoEnergy, L.L.C. and subsidiaries at December 31, 2005 and 2004, and theresults of their operations and their cash flows for each of the three years inthe period ended December 31, 2005, in conformity with accountingprinciples generally accepted in the United States of America.

As discussed in Notes 2 and 5 to the financialstatements, effective July 1, 2003, the Company changed its accounting forfinancial instruments with the characteristics of both liabilities and equityand effective December 31, 2005, the Company changed its accounting forconditional asset retirement obligations.

We have also audited, in accordance with the standardsof the Public Company Accounting Oversight Board (United States), theeffectiveness of the Company’s internal control over financial reporting as of December 31,2005, based on the criteria established in *Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission and our report dated March 16, 2006 expressed anunqualified opinion on management’s assessment of the effectiveness of theCompany’s internal control over financial reporting and an unqualified opinionon the effectiveness of the Company’s internal control over financialreporting.

/s/ DELOITTE &TOUCHE LLP

Houston,Texas

March 16, 2006

F-2

----

**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS**

| ** **                                                                                                                                    | ** ** | **December 31,**                                       | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                                                                                                    | ** ** | **2005**                                                    | ** ** | **2004** | ** ** |
| ** **                                                                                                                                    | ** ** | **(in thousands, except  unit information)** | ** ** |
| **ASSETS**                                                                                                                                    |       |                                                        |       |   |   |
| Current assets:                                                                                                                               |       |                                                        |       |   |   |
| Cash and cash equivalents                                                                                                                     |       | $                                                           | 25,297     |   | $ | 7,015 |   |
| Escrow cash                                                                                                                                   |       | —                                                      |       | 1,000 |   |
| Accounts receivable, net                                                                                                                      |       | 83,297                                                      |       | 37,045 |   |
| Accounts receivable from affiliates                                                                                                           |       | —                                                      |       | 1,141 |   |
| Risk management assets                                                                                                                        |       | 10,067                                                      |       | — |   |
| Prepayments and other current assets                                                                                                          |       | 2,474                                                       |       | 1,300 |   |
| Total current assets                                                                                                                          |       | 121,135                                                     |       | 47,501 |   |
| Property, plant and equipment, net                                                                                                            |       | 532,320                                                     |       | 119,683 |   |
| Intangible  assets, net                                                                                                                       |       | 97,551                                                      |       | 4,469 |   |
| Investment in  unconsolidated affiliates                                                                                                      |       | 7,901                                                       |       | 4,371 |   |
| Risk management  assets                                                                                                                       |       | 24,778                                                      |       | — |   |
| Other assets, net                                                                                                                             |       | 9,065                                                       |       | 2,375 |   |
| Total assets                                                                                                                                  |       | $                                                           | 792,750    |   | $ | 178,399 |   |
| **LIABILITIES  AND MEMBERS’ CAPITAL**                                                                                                    |       |                                                        |       |   |   |
| Current liabilities:                                                                                                                          |       |                                                        |       |   |   |
| Accounts payable                                                                                                                              |       | $                                                           | 96,001     |   | $ | 36,960 |   |
| Accounts payable to affiliates                                                                                                                |       | 189                                                         |       | 127 |   |
| Notes payable                                                                                                                                 |       | 1,272                                                       |       | 350 |   |
| Other current liabilities                                                                                                                     |       | 10,970                                                      |       | 777 |   |
| Total current liabilities                                                                                                                     |       | 108,432                                                     |       | 38,214 |   |
| Long-term debt                                                                                                                                |       | 398,000                                                     |       | 57,000 |   |
| Risk management  and other noncurrent liabilities                                                                                             |       | 4,515                                                       |       | 829 |   |
| Commitments and  contingencies (Note 14)                                                                                                 |       |                                                        |       |   |   |
| Members’ capital:                                                                                                                        |       |                                                        |       |   |   |
| Common units, no par value, 14,100,508 units and  7,056,252 units issued and outstanding as of December 31, 2005 and 2004,  respectively |       | 297,592                                                     |       | 94,325 |   |
| Subordinated units, no par value, 3,519,126 units  issued and outstanding as of December 31, 2005 and 2004                               |       | 10,379                                                      |       | 10,379 |   |
| Paid-in capital                                                                                                                               |       | 4,068                                                       |       | — |   |
| Accumulated deficit                                                                                                                           |       | (14,941                                                     | )          | (21,927 | ) |
| Deferred compensation                                                                                                                         |       | (3,949                                                      | )          | (421 | ) |
| Other comprehensive loss                                                                                                                      |       | (11,346                                                     | )          | — |   |
|                                                                                                                                          |       | 281,803                                                     |       | 82,356 |   |
| Total liabilities  and members’ capital                                                                                                  |       | $                                                           | 792,750    |   | $ | 178,399 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-3

----

**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS**

| ** **                                                                     | ** ** | **Year Ended December 31,**                      | ** ** |
|--------------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                                                     | ** ** | **2005**                                                        | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                     | ** ** | **(in thousands, except unit information)** | ** ** |
| Revenue:                                                                       |       |                                                            |       |   |   |   |   |
| Natural gas sales(1)                                                           |       | $                                                               | 496,551    |   | $ | 262,317 |   | $ | 315,521 |   |
| Natural gas sales—affiliates                                              |       | 355                                                             |       | 557 |   | 10 |   |
| Natural gas liquids sales                                                      |       | 224,695                                                         |       | 161,570 |   | 60,307 |   |
| Transportation, compression and processing fees                                |       | 15,079                                                          |       | 11,295 |   | 7,690 |   |
| Transportation, compression and processing  fees—affiliates               |       | 31                                                              |       | 75 |   | 33 |   |
| Other                                                                          |       | 11,032                                                          |       | 1,842 |   | 1,010 |   |
| Total revenue                                                                  |       | 747,743                                                         |       | 437,656 |   | 384,571 |   |
| Costs and  expenses:                                                           |       |                                                            |       |   |   |   |   |
| Cost of natural gas and natural gas liquids(2)                                 |       | 636,461                                                         |       | 381,615 |   | 348,336 |   |
| Cost of natural gas and natural gas  liquids—affiliates                   |       | 4,854                                                           |       | 2,465 |   | 2,390 |   |
| Transportation                                                                 |       | 1,862                                                           |       | 1,583 |   | 2,469 |   |
| Transportation—affiliates                                                 |       | 475                                                             |       | 492 |   | 181 |   |
| Operations and maintenance                                                     |       | 18,459                                                          |       | 12,486 |   | 10,854 |   |
| Depreciation and amortization                                                  |       | 17,052                                                          |       | 7,287 |   | 6,091 |   |
| General and administrative                                                     |       | 18,156                                                          |       | 9,217 |   | 5,849 |   |
| Taxes other than income                                                        |       | 1,178                                                           |       | 770 |   | 926 |   |
| Equity in (earnings) loss from unconsolidated  affiliates                      |       | (927                                                            | )          | (419 | ) | 127 |   |
| Total costs and expenses                                                       |       | 697,570                                                         |       | 415,496 |   | 377,223 |   |
| Operating income                                                               |       | 50,173                                                          |       | 22,160 |   | 7,348 |   |
| Other income  (expense):                                                       |       |                                                            |       |   |   |   |   |
| Interest and other income                                                      |       | 640                                                             |       | 85 |   | 43 |   |
| Interest and other financing costs                                             |       | (20,461                                                         | )          | (23,160 | ) | (12,108 | ) |
| Net income (loss)                                                              |       | $                                                               | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Basic net income  (loss) per equivalent unit (Notes 2 and 9):             |       |                                                            |       |   |   |   |   |
| Net income (loss)                                                              |       | $                                                               | 2.31       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Weighted average number of equivalent units                                    |       | 9,643                                                           |       | 2,599 |   | 1,405 |   |
| Diluted net  income (loss) per equivalent unit (Notes 2 and 9):           |       |                                                            |       |   |   |   |   |
| Net income (loss) per equivalent unit                                          |       | $                                                               | 2.29       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Weighted average number of equivalent units                                    |       | 13,254                                                          |       | 2,604 |   | 1,405 |   |
| (1) Includes  sales related to purchases/sales with the same counterparty:     |       | $                                                               | 32,384     |   | $ | — |   | $ | — |   |
| (2) Includes purchases  related to purchases/sales with the same counterparty: |       | $                                                               | 32,778     |   | $ | — |   | $ | — |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-4

----

**COPANO ENERGY, L.L.C. AND SUBSIDIARIES**

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

| ** **                                                                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                                      | ** ** | **(in thousands)**                    | ** ** |
| Cash Flows From Operating  Activities:                                                                          |       |                                       |       |   |   |   |   |
| Net income (loss)                                                                                               |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Adjustments  to reconcile net income (loss) to net cash provided by operating activities:                       |       |                                       |       |   |   |   |   |
| Depreciation and amortization                                                                                   |       | 17,052                                     |       | 7,287 |   | 6,091 |   |
| Amortization of debt issue costs                                                                                |       | 5,723                                      |       | 2,000 |   | 940 |   |
| Equity in (earnings) loss from unconsolidated  affiliates                                                       |       | (927                                       | )          | (419 | ) | 127 |   |
| Payment-in-kind interest on subordinated  debt                                                                  |       | —                                     |       | 814 |   | 3,908 |   |
| Payment-in-kind interest to preferred  unitholders                                                              |       | —                                     |       | 6,508 |   | 3,446 |   |
| Accretion of preferred unitholders warrant value                                                                |       | —                                     |       | 9,405 |   | 781 |   |
| Accretion of subsidiary warrant value                                                                           |       | —                                     |       | 405 |   | — |   |
| Deferred compensation                                                                                           |       | 1,283                                      |       | 53 |   | — |   |
| Other noncash items                                                                                             |       | 26                                         |       | (61 | ) | — |   |
| Changes  in assets and liabilities, net of acquisitions:                                                        |       |                                       |       |   |   |   |   |
| Accounts receivable                                                                                             |       | (17,986                                    | )          | (11,440 | ) | (1,150 | ) |
| Accounts receivable from affiliates                                                                             |       | 1,261                                      |       | (370 | ) | (504 | ) |
| Prepayments and other current assets                                                                            |       | 2,771                                      |       | 85 |   | 162 |   |
| Risk management assets                                                                                          |       | (42,635                                    | )          | — |   | — |   |
| Accounts payable                                                                                                |       | 19,658                                     |       | 5,591 |   | 5,101 |   |
| Accounts payable to affiliates                                                                                  |       | 62                                         |       | (1,244 | ) | 439 |   |
| Other current liabilities                                                                                       |       | (16,360                                    | )          | (2 | ) | 672 |   |
| Net cash provided by operating activities                                                                       |       | 280                                        |       | 17,697 |   | 15,296 |   |
| Cash Flows From Investing  Activities:                                                                          |       |                                       |       |   |   |   |   |
| Additions to property, plant and equipment and  intangible assets                                               |       | (10,054                                    | )          | (8,590 | ) | (6,054 | ) |
| Acquisitions, net of cash acquired                                                                              |       | (479,288                                   | )          | (330 | ) | (138 | ) |
| Investment in unconsolidated affiliates                                                                         |       | (2,722                                     | )          | — |   | — |   |
| Escrow cash                                                                                                     |       | 1,001                                      |       | 1 |   | (1 | ) |
| Other                                                                                                           |       | (645                                       | )          | — |   | — |   |
| Net cash used in investing activities                                                                           |       | (491,708                                   | )          | (8,919 | ) | (6,193 | ) |
| Cash Flows From Financing  Activities:                                                                          |       |                                       |       |   |   |   |   |
| Repayments of long-term debt                                                                                    |       | (94,000                                    | )          | (34,313 | ) | (21,800 | ) |
| Proceeds from long-term debt                                                                                    |       | 435,000                                    |       | 40,000 |   | 14,000 |   |
| Repayment of short-term notes payable                                                                           |       | (1,207                                     | )          | — |   | — |   |
| Repayment of subordinated debt                                                                                  |       | —                                     |       | (15,199 | ) | — |   |
| Repayments of other long-term obligations                                                                       |       | —                                     |       | (991 | ) | (89 | ) |
| Deferred financing costs                                                                                        |       | (9,802                                     | )          | (2,063 | ) | (135 | ) |
| Payment of subscription receivable                                                                              |       | —                                     |       | 143 |   | — |   |
| Distributions to special unitholders                                                                            |       | —                                     |       | (143 | ) | — |   |
| Distributions to unitholders                                                                                    |       | (23,366                                    | )          | (4,000 | ) | — |   |
| Proceeds from initial public offering of common  units, net of underwriting discounts and commissions of $8,050 |       | —                                     |       | 106,950 |   | — |   |
| Proceeds from private placement of common units                                                                 |       | 64,499                                     |       | — |   | — |   |
| Proceeds from private placement of Class B units                                                           |       | 135,503                                    |       | — |   | — |   |
| Capital contributions from Pre-Offering Investors  (Note 9)                                                |       | 4,068                                      |       | — |   | — |   |
| Equity offering costs                                                                                           |       | (1,074                                     | )          | (4,322 | ) | (798 | ) |
| Proceeds from option exercises                                                                                  |       | 89                                         |       | — |   | — |   |
| Redemption of preferred units                                                                                   |       | —                                     |       | (78,077 | ) | — |   |
| Distributions to preferred unitholders                                                                          |       | —                                     |       | — |   | (810 | ) |
| Redeem common units                                                                                             |       | —                                     |       | (13,950 | ) | — |   |
| Purchase warrants issued by subsidiary                                                                          |       | —                                     |       | (405 | ) | — |   |
| Net cash provided by (used in) financing activities                                                             |       | 509,710                                    |       | (6,370 | ) | (9,632 | ) |
| Net increase (decrease) in cash and cash equivalents                                                            |       | 18,282                                     |       | 2,408 |   | (529 | ) |
| Cash and cash equivalents, beginning of year                                                                    |       | 7,015                                      |       | 4,607 |   | 5,136 |   |
| Cash and cash  equivalents, end of year                                                                         |       | $                                          | 25,297     |   | $ | 7,015 |   | $ | 4,607 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-5

----

**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL AND COMPREHENSIVE INCOME (LOSS)**

| ** ** | ** ** | **Common** | ** ** | **Class B** | ** ** | **Subordinated** | ** ** | **Common Special** | ** ** | **Junior** | ** ** | **Junior Special** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Other** | ** ** | ** ** | ** ** | **Total  Compre-** | ** ** |
|------------|------------|------------|------------|------------------|------------|------------------|------------|-------------------------|------------|------------|------------|-------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|-----------|------------|------------|------------|--------------------|------------|

| ** **                                                      | ** ** | **Number  of Units** | ** ** | **Common  Units**              | ** ** | **Number  of Units** | ** ** | **Class B  Units**                                 | ** ** | **Number  of Units** | ** ** | **Subord-  inated  Units**                        | ** ** | **Number  of Units** | ** ** | **Common  Special  Units**                                    | ** ** | **Number  of Units** | ** ** | **Junior  Units**                     | ** ** | **Number  of Units** | ** ** | **Junior  Special  units**                         | ** ** | **Paid-in  Capital** | ** ** | **Accumulated  Earnings  (Deficit)**                          | ** ** | **Subscription  Receivable**                                                                      | ** ** | **Deferred  Compen-  sation**                                 | ** ** | **Compre-  hensive  Loss**          | ** ** | **Total**                | ** ** | **hensive  Income  (Loss)**                             | ** ** |
|-----------------------------------------------------------------|------------|---------------------------|------------|--------------------------------|------------|---------------------------|------------|---------------------------------------------------------|------------|---------------------------|------------|---------------------------------------------------|------------|---------------------------|------------|---------------------------------------------------------------|------------|---------------------------|------------|---------------------------------------|------------|---------------------------|------------|----------------------------------------------------|------------|----------------------|------------|---------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|-------------------------------------|------------|--------------------------|------------|---------------------------------------------------------|------------|
| ** **                                                      | ** ** | **(in thousands)**   | ** ** |
| **Balance,  December 31, 2002**                            |       | 1,299                     |       | $    3,471 |       | —                    |       | $        — |       | —                    |       | $       — |       | 54                        |       | $         54     |       | 620                       |       | $   526                |       | 18                        |       | $        9 |       | $ 11,095        |       | $         (8,289 | )          | $              (63          | )          | $         — |       | $     (226 | )          | $   6,577 |       | $        — |       |
| Equity issuance  costs                                          |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | 1,258                |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 1,258                    |       | —                                                  |       |
| Payment-in-kind  preferred distribution                         |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (2,453                                                        | )          | —                                                                                            |       | —                                                        |       | —                              |       | (2,453                   | )          | —                                                  |       |
| Accretion of  preferred units                                   |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (743                                                          | )          | —                                                                                            |       | —                                                        |       | —                              |       | (743                     | )          | —                                                  |       |
| Distributions to  preferred unitholders                         |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (810                                                          | )          | —                                                                                            |       | —                                                        |       | —                              |       | (810                     | )          | —                                                  |       |
| Issuance common  and junior special units                       |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | 100                       |       | 100                                                           |       | —                    |       | —                                |       | 40                        |       | 20                                                 |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 120                      |       | —                                                  |       |
| Subscription  receivable                                        |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | (120                                                                                              | )          | —                                                        |       | —                              |       | (120                     | )          | —                                                  |       |
| Net loss                                                        |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (4,717                                                        | )          | —                                                                                            |       | —                                                        |       | —                              |       | (4,717                   | )          | (4,717                                                  | )          |
| Change in fair  value of derivatives used for hedging purposes  |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | 226                                 |       | 226                      |       | 226                                                     |       |
| Comprehensive loss                                              |       |                      |       |                           |       |                      |       |                                                    |       |                      |       |                                              |       |                      |       |                                                          |       |                      |       |                                  |       |                      |       |                                               |       |                 |       |                                                          |       |                                                                                              |       |                                                          |       |                                |       |                     |       | $  (4,491                                     | )          |
| **Balance,  December 31, 2003**                            |       | 1,299                     |       | 3,471                          |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | 154                       |       | 154                                                           |       | 620                       |       | 526                                   |       | 58                        |       | 29                                                 |       | 12,353               |       | (17,012                                                       | )          | (183                                                                                              | )          | —                                                        |       | —                              |       | (662                     | )          | —                                                  |       |
| Subscription  receivable                                        |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | 183                                                                                               |       | —                                                        |       | —                              |       | 183                      |       | —                                                  |       |
| Distribution to special unitholders                             |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | (121                                                          | )          | —                    |       | —                                |       | —                    |       | (22                                                | )          | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | (143                     | )          | —                                                  |       |
| Distribution to  pre-Offering unitholders                       |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (4,000                                                        | )          | —                                                                                            |       | —                                                        |       | —                              |       | (4,000                   | )          | —                                                  |       |
| Unit exchange                                                   |       | 739                       |       | 2,540                          |       | —                    |       | —                                                  |       | 3,519                     |       | 10,379                                            |       | (154                      | )          | (33                                                           | )          | (620                      | )          | (526                                  | )          | (58                       | )          | (7                                                 | )          | (12,353              | )          | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | —                   |       | —                                                  |       |
| Issuance of common units to public                         |       | 5,750                     |       | 115,000                        |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 115,000                  |       | —                                                  |       |
| Offering costs                                                  |       | —                    |       | (13,170                        | )          | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | (13,170                  | )          | —                                                  |       |
| Redeem common units from certain pre-Offering unitholders  |       | (750                      | )          | (13,950                        | )          | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | (13,950                  | )          | —                                                  |       |
| Issuance of  restricted units                                   |       | 18                        |       | 434                            |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | (434                                                          | )          | —                              |       | —                   |       | —                                                  |       |
| Stock-based  compensation                                       |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | 13                                                            |       | —                              |       | 13                       |       | —                                                  |       |
| Net loss                                                        |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (915                                                          | )          | —                                                                                            |       | —                                                        |       | —                              |       | (915                     | )          | (915                                                    | )          |
| Comprehensive loss                                              |       |                      |       |                           |       |                      |       |                                                    |       |                      |       |                                              |       |                      |       |                                                          |       |                      |       |                                  |       |                      |       |                                               |       |                 |       |                                                          |       |                                                                                              |       |                                                          |       |                                |       |                     |       | $     (915                     | )          |
| **Balance,  December 31, 2004**                            |       | 7,056                     |       | 94,325                         |       | —                    |       | —                                                  |       | 3,519                     |       | 10,379                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (21,927                                                       | )          | —                                                                                            |       | (421                                                          | )          | —                              |       | 82,356                   |       | —                                                  |       |
| Capital  contributions from Pre-Offering Investors              |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | 4,068                |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 4,068                    |       | —                                                  |       |
| Private placement  of units                                     |       | 2,082                     |       | 64,499                         |       | 4,831                     |       | 135,503                                                 |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 200,002                  |       | —                                                  |       |
| Offering costs                                                  |       | —                    |       | (777                           | )          | —                    |       | (858                                                    | )          | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | (1,635                   | )          | —                                                  |       |
| Conversion of  Class B units into common units             |       | 4,831                     |       | 134,645                        |       | (4,831                    | )          | (134,645                                                | )          | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | —                   |       | —                                                  |       |
| Distributions to  unitholders                                   |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | (23,366                                                       | )          | —                                                                                            |       | —                                                        |       | —                              |       | (23,366                  | )          | —                                                  |       |
| Option exercises                                                |       | 5                         |       | 89                             |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 89                       |       | —                                                  |       |
| Issuance of  restricted units                                   |       | 127                       |       | 4,811                          |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | (4,811                                                        | )          | —                              |       | —                   |       | —                                                  |       |
| Stock-based  compensation                                       |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | 1,283                                                         |       | —                              |       | 1,283                    |       | —                                                  |       |
| Net income                                                      |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | 30,352                                                        |       | —                                                                                            |       | —                                                        |       | —                              |       | 30,352                   |       | 30,352                                                  |       |
| Changes in fair  value of derivatives used for hedging purposes |       | —                    |       | —                         |       | —                    |       | —                                                  |       | —                    |       | —                                            |       | —                    |       | —                                                        |       | —                    |       | —                                |       | —                    |       | —                                             |       | —               |       | —                                                        |       | —                                                                                            |       | —                                                        |       | (11,346                             | )          | (11,346                  | )          | (11,346                                                 | )          |
| Comprehensive  income                                           |       |                      |       |                           |       |                      |       |                                                    |       |                      |       |                                              |       |                      |       |                                                          |       |                      |       |                                  |       |                      |       |                                               |       |                 |       |                                                          |       |                                                                                              |       |                                                          |       |                                |       |                     |       | $ 19,006                                           |       |
| **Balance,  December 31, 2005**                            |       | 14,101                    |       | $ 297,592                 |       | —                    |       | $        — |       | 3,519                     |       | $ 10,379                                     |       | —                    |       | $         — |       | —                    |       | $     — |       | —                    |       | $      —        |       | $ 4,068         |       | $       (14,941            | )          | $               — |       | $  (3,949                                           | )          | $ (11,346                      | )          | $ 281,803           |       |                                                    |       |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

F-6

 

----

**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**Note 1—Organization**

Copano Energy, L.L.C., a Delaware limited liabilitycompany, was formed in August 2001 to acquire entities owning businessesoperating under the Copano name since 1992. We, through our wholly-ownedsubsidiaries, provide midstream energy services, including gathering,transportation, treating, processing and conditioning services in the TexasGulf Coast region and, as a result of the acquisition of ScissorTail Energy,LLC (“ScissorTail”) on August 1, 2005, in central and eastern Oklahoma****(see Note 4). *Unlessthe context requires otherwise, references to “Copano,” “we,” “our,” “us,” orlike terms refer to Copano Energy, L.L.C. and its wholly-owned subsidiaries,including ScissorTail*.

Our natural gas pipelines collect natural gas fromdesignated points near producing wells and transport these volumes to third-partypipelines, our gas processing plants, third party processing plants, localdistribution companies, power generation facilities and industrial consumers. Naturalgas delivered to our gas processing plants, either on our pipelines or a third-partypipeline, is treated to remove contaminants, conditioned or processed toextract mixed natural gas liquids, or NGLs, and then fractionated or separatedinto select component NGL products, including ethane, propane, isobutene,normal butane, natural gasoline and stabilized condensate. We also own andoperate an NGL products pipeline extending from our Houston Central ProcessingPlant near Sheridan, Texas to the Houston area. We refer to our natural gaspipeline Texas operating subsidiaries collectively as “Texas Gulf CoastPipelines,” to our Texas processing and related activities collectively as “TexasGulf Coast Processing” and to our operations in central and eastern Oklahoma as“Mid-Continent Operations.”

On November 15, 2004,we completed our initial public offering (the “Offering”) of 5,750,000 commonunits, inclusive of 750,000 common units that were issued as a result of theunderwriters’ exercise of their over-allotment option. The common units issuedin the Offering were sold at $20.00 per common unit and the net proceeds fromthe Offering were used (i) to redeem our redeemable preferred units fromcertain of our investors existing prior to the Offering (our “Pre-OfferingInvestors”), (ii) to reduce existing indebtedness, (iii) to pay otherobligations, (iv) to pay expenses of the Offering and (v) to redeemcommon units, on a pro rata basis, from certain Pre-Offering Investors.

**Note 2—Summary of Significant Accounting Policies**

*Basis of Presentationand Principles of Consolidation*

The accompanying consolidated financial statements andrelated notes include our assets, liabilities and results of operations foreach of the periods presented. Although we, through certain of oursubsidiaries, own a 62.5% equity investment in Webb/Duval Gatherers (“WebbDuval”), a Texas general partnership, and a majority interest in Southern Dome,LLC (“Southern Dome”), a Delaware limited liability company, we account forboth of these investments using the equity method of accounting because theminority general partners or members have substantive participating rights withrespect to the management of Webb Duval and Southern Dome (see Note 6). Allsignificant intercompany accounts and transactions are eliminated in theconsolidated financial statements.

Two of our wholly-ownedsubsidiaries, Copano General Partners, Inc. (“CGP”) and Copano EnergyFinance Corporation (“CEFC”), both Delaware corporations, are the only entitieswithin our consolidated group subject to federal income taxes. CGP’s operationsprimarily include its indirect ownership of the managing general partnerinterest in certain of the Texas Gulf Coast Pipelines entities and CEFC wasformed in July 2005, and is a co-issuer of the senior notes issued in February 2006(see Note 7). As of December 31, 2004, CGP had estimated a netoperating loss (“NOL”) carryforward of approximately 

F-7

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

$265,000,for which a valuation allowance had been recorded. During the year ended December 31,2005, we determined that CGP had utilized this NOL carryforward. No significantincome tax expense was recognized for the years ended December 31, 2005,2004 and 2003. Except for income allocated to CGP, income is taxable directlyto our unitholders holding our membership interests.

*Use of Estimates*

The preparation of thefinancial statements in conformity with accounting policies generally acceptedin the United States of America requires management to make estimates andassumptions that affect the reported amounts of assets, liabilities, revenuesand expenses and disclosure of contingent assets and liabilities that exist atthe date of the financial statements. Although our management believes theestimates are appropriate, actual results can differ from those estimates.

*Cash and CashEquivalents*

Cash and cash equivalentsinclude certificates of deposit with maturities of three months or less at thetime of purchase.

*Escrow Cash*

Escrow cash includes cashthat was contractually restricted for interest expense due currently. Restrictedcash and cash equivalents are classified as a current or non-current assetbased on their designated purpose. Amount outstanding as of December 31,2004 represented an escrow for the CHC Facility discussed in Note 7.

*Concentration andCredit Risk*

Financial instruments that potentially subject us toconcentrations of credit risk consist principally of cash and cash equivalentsand accounts receivable.

We place our cash and cashequivalents with high-quality institutions and in money market funds. We deriveour revenue from customers primarily in the natural gas and utility industries.These industry concentrations have the potential to impact our overall exposureto credit risk, either positively or negatively, in that our customers could beaffected by similar changes in economic, industry or other conditions. However,we believe that the credit risk posed by this industry concentration is offsetby the creditworthiness of our customer base. Our portfolio of accountsreceivable is comprised primarily of mid-size to large domestic corporateentities.

F-8

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Allowance forDoubtful Accounts*

We extend credit tocustomers and other parties in the normal course of business. Estimated losseson accounts receivable are provided through an allowance for doubtful accounts.In evaluating the level of established reserves, we make judgments regardingeach party’s ability to make required payments, economic events and otherfactors. As the financial condition of any party changes, circumstances developor additional information becomes available, adjustments to the allowance fordoubtful accounts may be required. We have established various procedures tomanage our credit exposure, including initial credit approvals, credit limitsand rights of offset. We also use prepayments and guarantees to limit creditrisk to ensure that our management’s established credit criteria are met. Theactivity in the allowance for doubtful accounts is as follows (in thousands):

| ** **                         | ** ** | **Balance at  Beginning  of Period** | ** ** | **Charged to  Expense** | ** ** | **Write-Offs,  Net of  Recoveries** | ** ** | **Balance at  End of  Period** | ** ** |
|------------------------------------|------------|-------------------------------------------|------------|------------------------------|------------|-------------------------------------|------------|--------------------------------|------------|
| Year ended  December 31, 2005 |       |                                      | $          | 356                          |       |                                |       | $                              | (285       | ) |   |   | $ | (7 | ) |   |   | $ | 64 |   |   |
| Year ended  December 31, 2004 |       |                                      | $          | 200                          |       |                                |       | $                              | 202        |   |   |   | $ | (46 | ) |   |   | $ | 356 |   |   |
| Year ended  December 31, 2003 |       |                                      | $          | —                       |       |                                |       | $                              | 208        |   |   |   | $ | (8 | ) |   |   | $ | 200 |   |   |

 

*Property, Plant andEquipment*

Ourproperty, plant and equipment consist of intrastate gas transmission systems,gas gathering systems, gas processing, conditioning and treating facilities andother related facilities, which are carried at cost less accumulateddepreciation. We charge repairs and maintenance against income when incurredand capitalize renewals and betterments, which extend the useful life or expandthe capacity of the assets. We calculate depreciation on the straight-linemethod principally over 20-year and 30-year estimated useful livesof our assets. The weighted average useful lives are as follows:

| Pipelines and equipment             |   | 24  years |
|-------------------------------------|--------|-----------|
| Gas processing plant and  equipment |   | 28  years |
| Office furniture and equipment      |   | 5 years   |

 

We capitalize interest on major projects duringextended construction time periods. Such interest is allocated to property,plant and equipment and amortized over the estimated useful lives of therelated assets.

We review long-livedassets for impairment whenever there is evidence that the carrying value ofsuch assets may not be recoverable. This review consists of comparing thecarrying value of the asset with the asset’s expected future undiscounted cashflows without interest costs. An impairment loss would be recognized whenestimated future cash flows expected to result from the use of the asset andits eventual disposition is less than the asset’s carrying value. Estimates ofexpected future cash flows represent our management’s best estimate based onreasonable and supportable assumptions.

*Intangible Assets*

Ourintangible assets consist of rights-of-way, easements, contracts and anacquired customer relationship, which we amortize over the term of theagreement or estimated useful life. Amortization expense was $2,503,000,$434,000, and $377,000 for the years ended December 31, 2005, 2004 and2003, respectively. Estimated aggregate amortization expense for each of thefive succeeding fiscal years is 

F-9

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

approximately: *2006—*$5,387,000;*2007—*$5,347,000; *2008—*$5,280,000; *2009—*$5,211,000; and *2010—*$5,180,000. Intangible assetsconsisted of the following (in thousands):

| ** **                            | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Rights-of-way  and easements, at cost |       | $                     | 59,693     |   | $ | 6,552 |   |
| Contracts                             |       | 42,444                |       | — |   |
| Customer  relationship                |       | 725                   |       | 725 |   |
| Less accumulated  amortization        |       | (5,311                | )          | (2,808 | ) |
| Intangible  assets, net               |       | $                     | 97,551     |   | $ | 4,469 |   |

 

For the years ended December 31, 2005 and 2004,the weighted average amortization period for all of our intangible assets was20 years and 17.2 years, respectively. The weighted averageamortization period for our rights-of-way and easements andcontracts was 24 years and 14.6 years, respectively, as of December 31,2005.

*Other Assets*

Other assets primarilyconsist of costs associated with debt issuance costs and long-term contractsnet of related accumulated amortization. Amortization of other assets iscalculated using the straight-line method over the maturity of the associateddebt or the expiration of the contract.

*Transportation andExchange Imbalances*

In the course oftransporting natural gas and natural gas liquids for others, we may receive forredelivery different quantities of natural gas or natural gas liquids than thequantities actually redelivered. These transactions result in transportationand exchange imbalance receivables or payables that are recovered or repaidthrough the receipt or delivery of natural gas or natural gas liquids in futureperiods, if not subject to cashout provisions. Imbalance receivables areincluded in accounts receivable and imbalance payables are included in accountspayable on the consolidated balance sheets and marked-to-market using currentmarket prices in effect for the reporting period of the outstanding imbalances.As of December 31, 2005 and 2004, we had imbalance receivables totaling$743,000 and $454,000 and imbalance payables totaling $373,000 and $602,000,respectively. Changes in market value and the settlement of any such imbalanceat a price greater than or less than the recorded imbalance results in eitheran upward or downward adjustment, as appropriate, to the cost of natural gassold.

*Asset RetirementObligation*

**In June 2001, the FinancialAccounting Standards Board (“FASB”) issued Statement of Financial AccountingStandards (“SFAS”) No. 143, *“Accounting for Asset RetirementObligations.”*  This statementrequires us to record the fair value of a liability for legal obligationsassociated with the retirement obligations of tangible long-lived assets in theperiod in which the obligation is incurred and can be reasonably estimated. Whenthe liability is initially recorded, a corresponding increase in the carryingamount of the related long-lived asset is recorded. Over time, accretion of theliability is recognized each period, and the capitalized cost is depreciatedover the useful life of the related asset. Upon settlement of the liability, anentity either settles the obligation for its recorded amount or incurs a gainor loss on settlement. The standard became effective for us on January 1,2003.**

F-10

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Under the implementation guidelines of SFAS No. 143,we reviewed our long-lived assets for asset retirement obligations (“ARO”), and based on our analysis, we determined we werenot required to recognize any potential liabilities under SFAS 143. Futureamortization of the ARO asset and accretion of the ARO liability will berecognized in earnings.

In March 2005, theFASB issued FASB Interpretation No. (“FIN”) 47, *“Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143.”*  FIN 47 clarifies that the term,conditional asset retirement obligation as used in SFAS No. 143,refers to a legal obligation to perform an asset retirement activity in whichthe timing and/or method of settlement are conditional upon a future event thatmay or may not be within the control of the entity. Even though uncertaintyabout the timing and/or method of settlement exists and may be conditional upona future event, the obligation to perform the asset retirement activity isunconditional. Accordingly, an entity is required to recognize a liability forthe fair value of a conditional asset retirement obligation if the fair valueof the liability can be reasonably estimated. In these circumstances, we arerequired to determine if there is a range of potential settlement dates and theprobabilities associated with this range based on a variety of factorsincluding the entity’s past practice, industry practice, management’s intent,and the assets economic life. The fair value of a liability for the conditionalasset retirement obligation should be recognized when incurred generally uponacquisition, construction or development or through the normal operation of theasset. SFAS No. 143 acknowledges that in some cases, sufficientinformation may not be available to reasonably estimate the fair value of anasset retirement obligation. FIN 47 also clarifies when an entity wouldhave sufficient information to reasonably estimate the fair value of an assetretirement obligation. We adopted FIN 47 effective December 31, 2005and the adoption of FIN 47 did not have a significant impact on ourfinancial position, results of operations or cash flows. See Note 5.

*Revenue Recognition*

Our natural gas and natural gas liquids revenue isrecognized in the period when the physical product is delivered to the customerat contractually agreed-upon pricing.

A significant portion of our sale and purchasearrangements are accounted for on a gross basis in the statements of operationsas natural gas sales and costs of natural gas, respectively. These transactionsare contractual arrangements that establish the terms of the purchase ofnatural gas at a specified location and the sale of natural gas at a differentlocation at the same or at another specified date. These arrangements aredetailed either jointly, in a single contract or separately, in individualcontracts that are entered into concurrently or in contemplation of one anotherwith a single or multiple counterparties. Both transactions require physicaldelivery of the natural gas and the risk and reward of ownership are evidencedby title transfer, assumption of environmental risk, transportation scheduling,credit risk and counterparty nonperformance risk.

We occasionally enter into buy/sell arrangements thatare accounted for on a net basis in the statements of operations as either anatural gas sale or a cost of natural gas, as appropriate.

Transportation,compression and processing-related revenue are recognized in the periodwhen the service is provided and include our fee-based service revenuefor services such as transportation, compression and processing includingprocessing under tolling arrangements.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Derivatives*

SFAS No. 133, *“Accounting for DerivativeInstruments and Hedging Activities,”* as amended, establishesaccounting and reporting standards for derivative instruments, includingcertain derivative instruments embedded in other contracts, and for hedgingactivities. In accordance with SFAS No. 133, we recognize all derivativesas either risk management assets or liabilities in our consolidated balance sheetsand measure those instruments at fair value. Changes in the fair value offinancial instruments over time are recognized into earnings unless specifichedging criteria are met. If the financial instruments meet the hedging criteria,changes in fair value will be recognized in earnings for fair value hedges andin other comprehensive income for the effective portion of cash flow hedges. Ineffectivenessin cash flow hedges is recognized in earnings in the period in which the ineffectivenessoccurs. Gains and losses on cash flow hedges are reclassified to operatingrevenue as the forecasted transactions occur. We included changes in our riskmanagement activities in cash flow from operating activities on theconsolidated statement of cash flows.

SFAS No. 133 provides that normal purchases andnormal sales contracts are not subject to the statement. Normal purchases andnormal sales are contracts that provide for the purchase or sale of somethingother than a financial instrument or derivative instrument that will bedelivered in quantities expected to be used or sold by the reporting entityover a reasonable period in the normal course of business. Our forward naturalgas purchase and sales contracts are designated as normal purchases and sales. Substantiallyall forward contracts fall within a one-month to five-year terms; however, wedo have certain contracts which extend through the life of the dedicatedproduction.

We use financialinstruments such as puts, swaps, and other derivatives to mitigate the risks toearnings and cash flows resulting from changes in commodity prices and interestrates. We recognize these transactions as assets and liabilities on ourconsolidated balance sheet based on the instrument’s fair value. All of ourfinancial instruments have been designated and accounted for as cash flowhedges. See Note 12 for a description of our risk management activities.

*Accounting forCertain Financial Instruments with Characteristics of Both Liabilities andEquity*

In May 2003, the FASB issued SFAS No. 150, *“Accounting for Certain Financial Instruments with Characteristics ofBoth Liabilities and Equity.”* SFAS No. 150 establishes standards for how an issuer classifies andmeasures certain instruments with characteristics of both liabilities andequity. SFAS No. 150 requires that an issuer classify such a financialinstrument as a liability (or asset in some circumstances). We adopted SFAS No. 150effective July 1, 2003. Upon adoption, we began classifying our redeemablepreferred units as a liability and began recording the value of thepaid-in-kind (“PIK”) preferred unit distributions issued to the redeemablepreferred unitholders as interest expense, whereas prior to the adoption ofSFAS No. 150, we recorded these distributions as a direct increase to theaccumulated deficit.

*Net Income (Loss)Per Unit*

Basic net income (loss) per equivalent unit excludesdilution and is computed by dividing net income (loss) attributable to theunitholders by the weighted average number of equivalent units outstandingduring the period. Dilutive net income (loss) per unit reflects potentialdilution and is computed by dividing net income (loss) attributable to the unitholdersby the weighted average number of equivalent units outstanding during theperiod increased by the number of additional units that would have beenoutstanding if the dilutive potential units had been exercised.

F-12

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Basicand diluted net income (loss) per equivalent unit is calculated as follows (inthousands, except per unit amounts). For periods prior to the Offering,equivalent units were calculated using the weighted average of pre-Offeringcommon units and common special units adjusted by a conversion or exchangefactor to reflect the exchange of pre-Offering common units for post-Offeringcommon units immediately prior to completion of the Offering (see Note 9).

| ** **                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Net income (loss)                                               |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Less net income  attributable to subordinated unitholders       |       | (8,115                                     | )          | — |   | — |   |
| Net income  (loss)—basic                                   |       | 22,237                                     |       | (915 | ) | (4,717 | ) |
| Net income  attributable to subordinated unitholders            |       | 8,115                                      |       |   |   |   |   |
| Accretion of  preferred units                                   |       | —                                     |       | — |   | (743 | ) |
| Cash  distributions to preferred unitholders                    |       | —                                     |       | — |   | (810 | ) |
| Payment in kind  distributions to pre-IPO preferred unitholders |       | —                                     |       | — |   | (2,453 | ) |
| Net income (loss)  available—diluted                       |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (8,723 | ) |
| Basic weighted  average equivalent units*                       |       | 9,643                                      |       | 2,599 |   | 1,405 |   |
| Dilutive weighted  average equivalent units**                   |       | 13,254                                     |       | 2,604 |   | 1,405 |   |
| Basic net income (loss) per equivalent unit*                    |       | $                                          | 2.31       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Diluted net income  (loss) per equivalent unit**                |       | $                                          | 2.29       |   | $ | (0.35 | ) | $ | (6.21 | ) |

----

*                    Basic weightedaverage equivalent units exclude subordinated units in periods of net income.

**             We had 91,564potentially dilutive employee unit options outstanding and no potentiallydilutive restricted units outstanding during the year ended December 31,2005. We had 5,208 potentially dilutive employee unit options outstanding duringthe year ended December 31, 2004 and 3,750,000 potentially dilutivewarrants outstanding during the year ended December 31, 2003. Thesepotentially dilutive option units and warrants were excluded from the dilutiveloss per equivalent unit calculation because to include these options andwarrants would have been anti-dilutive since we reported losses for theyears ended December 31, 2003. Subordinated units and Class B unitsshare earnings equally with common units.

Net loss per unit for the year ended December 31,2003 has not been presented for junior units and junior special units as suchunits were not entitled to share in earnings for the periods presented.

*Accounting forStock-Based Compensation*

We use the intrinsicvalue method established by Accounting Principles Board Opinion (“APB”) No. 25,*“Accountingfor Stock Issued to Employees”* to value unit options issued to ouremployees under our long-term incentive plan adopted on November 15, 2004.In accordance with APB No. 25 for fixed unit options, compensation isrecorded to the extent the fair value of the unit exceeds the exercise price ofthe option at the measurement date. Compensation costs for fixed awards withpro rata vesting are recognized on a straight-line basis over the vestingperiod. For the years ended December 31, 2005 and 2004, the cost of thisstock-based compensation program had no impact on our net income (loss), as alloptions granted had an exercise price equal to the market value of theunderlying common unit on the date of grant.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Ifcompensation expense related to the issuance of the options had been determinedby applying the fair value method prescribed in SFAS No. 123, our netincome (loss) and net income (loss) per equivalent unit would have approximatedthe pro forma amounts below (in thousands):

| ** **                                                                          | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Net income  (loss), as reported                                                     |       | $                                          | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Less: Stock-based  employee compensation expense determined under fair value method |       | 459                                        |       | 17 |   | — |   |
| Pro forma net  income (loss)                                                        |       | $                                          | 29,893     |   | $ | (932 | ) | $ | (4,717 | ) |
| Net income (loss)  per equivalent unit:                                             |       |                                       |       |   |   |   |   |
| Basic—as reported                                                              |       | $                                          | 2.31       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Basic—pro forma                                                                |       | $                                          | 2.27       |   | $ | (0.36 | ) | $ | (6.21 | ) |
| Diluted—as reported                                                            |       | $                                          | 2.29       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Diluted—pro forma                                                              |       | $                                          | 2.26       |   | $ | (0.36 | ) | $ | (6.21 | ) |

 

The effects of applying SFAS No. 123 in this proforma disclosure are not indicative of future amounts.

The fair value of each unit option granted isestimated on the date of grant using the Black-Scholes option-pricing modelwith the following assumptions for 2005: exercise price of $36.51, expected volatility rate of 26.1%, expecteddistribution yield of 6.34%, risk-free interest rate of 4.165% and expectedlife of 7 years. The Black-Scholes average fair value of options granted in2005 was $5.14 per unit.

The fair value of each unit option granted isestimated on the date of grant using the Black-Scholes option-pricing modelwith the following assumptions for 2004: exercise price of $20.00, expected volatility rate of 17.86%, expecteddistribution yield of 6.18%, risk-free interest rate of 3.12% and expected lifeof 7 years. The Black-Scholes average fair value of options granted in 2004 was$1.44 per unit.

We did not grant anyoptions during 2003.

**Note 3—New Accounting Pronouncements**

*Share Based Payment*

In December 2004, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”)No. 123 (revised 2004), or SFAS No. 123(R), *“Share-BasedPayment,”* which establishes accounting standards for all transactions in which anentity exchanges its equity instruments for goods or services. SFAS No. 123(R) focusesprimarily on accounting for transactions with employees and carries forwardwithout change to prior guidance for share-based payments for transactions withnon-employees. SFAS No. 123(R) eliminates the intrinsic valuemeasurement objective in APB No. 25 and generally requires us to measurethe cost of employee services received in exchange for an award of equity instruments based on the fair value of the awardon the date of the grant.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

The standard requires grant date fair value to beestimated using either an option-pricing model that is consistent with theterms of the award or a market observed price, if such a price exists. Suchcost must be recognized over the period during which an employee is required toprovide services in exchange for the award (which is usually the vestingperiod). The standard also requires us to estimate the number of instrumentsthat will ultimately be issued, rather than accounting for forfeitures as they occur.We are required to apply SFAS No. 123(R) to all equity awardsgranted, modified or settled by January 1, 2006. We are also required touse either the “modified prospective method” or the “modified retrospectivemethod.”  Under the modified prospectivemethod, we must recognize compensation cost for all awards granted after weadopt the standard and for the unvested portion of previously granted awardsthat are outstanding on that date. Under the modified retrospective method, wemust restate previously issued financial statements to recognize the amounts wepreviously calculated and reported on a pro forma basis, as if the priorstandard had been adopted. Under both methods, we are permitted to use either astraight line or an accelerated method to amortize the cost as an expense forawards with graded vesting. We will adopt this standard on January 1,2006.

We have commenced theanalysis of the impact of SFAS No. 123(R), but have not yet decidedwhether we will use the modified prospective method or elect to use themodified retrospective method or whether we will elect to use straight lineamortization or an accelerated method. Accordingly, we cannot currentlyquantify with precision the effect that this standard would have on ourfinancial position or results of operations in the future, except that weprobably will recognize a greater expense for any awards that we may grant inthe future than we would recognize using the current guidance. The adoption ofthis statement is not expected to have a material impact on our futurefinancial position or results of operations.

*Exchanges ofNonmonetary Assets an amendment of APB No. 29.*

In December 2004, theFASB issued SFAS No. 153, *“Exchanges of NonmonetaryAssets an amendment of APB Opinion No. 29.”*  This statement amends APB No. 29 toeliminate the exception for nonmonetary exchanges of similar productive assetsand replaces it with a general exception for exchanges of nonmonetary assetsthat do not have commercial substance. The statement specifies that a nonmonetaryexchange has commercial substance if the future cash flows of the entity areexpected to change significantly as a result of the exchange. We adopted thisstatement beginning July 1, 2005. The adoption of this statement had noimpact on our previously issued financial statements and is not expected tohave a material impact on future financial statements.

*Accounting Changesand Error Corrections*

In May 2005, the FASBissued SFAS No. 154, *“Accounting Changes andError Corrections.”* SFAS No. 154 requires companies to recognize changes inaccounting principle, including changes required by a new accountingpronouncement when the pronouncement does not include specific transitionprovisions, retrospectively to prior periods’ financial statements. SFAS No. 154is effective for accounting changes and corrections of errors made in fiscalyears beginning after December 15, 2005. We do not believe that theadoption of SFAS No. 154 will have a material effect on our financialposition or results of operations.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Accounting forPurchases and Sales of Inventory with the Same Counterparty*

In September 2005,the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on theissue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13,*“Accounting for Purchases and Sales of Inventorywith the Same Counterparty”* (“Issue 04-13”). As part of Issue04-13, the EITF is requiring that all buy/sell arrangements be reflectedon a net basis, such that the purchase and sale are netted and shown as eithera net purchase or a net sale in the income statement. This requirement iseffective for new arrangements entered into after March 31, 2006. If thisrequirement had been effective for the years ended December 31, 2005, 2004and 2003, the reported natural gas sales revenues and the reported cost ofnatural gas and natural gas liquids would be reduced by the amounts shown infootnotes (1) and (2) to the consolidated statements of operations. Wedo not expect that the adoption of Issue 04-13 will have a materialeffect on our financial position, results of operations or cash flows.

**Note 4—Acquisitions**

*Acquisition ofScissorTail Energy, LLC*

On August 1, 2005, we completed our acquisitionof all of the membership interests in Tulsa-based ScissorTail for $499,135,000(the “ScissorTail Acquisition”). The results of operations for ScissorTail areincluded in our results beginning August 1, 2005. ScissorTail providesnatural gas midstream services in central and eastern Oklahoma and its assetsprimarily consist of gathering pipelines and three processing plants. Inconnection with the ScissorTail Acquisition, we, through ScissorTail, nowoperate and hold a majority interest in Southern Dome in partnership with theprior ScissorTail ownership group. Southern Dome was formed to engage in themidstream gas gathering and processing business and related operations inOklahoma County, Oklahoma. In connection with the ScissorTail Acquisition, weissued 85,998 restricted common units and 169,002 options to acquire commonunits to employees of ScissorTail subject, in each case, to a five-year vestingschedule.

We financed theScissorTail Acquisition and related transactions and costs with proceeds fromthe following:

·       Borrowingsof approximately $179.0 million of the $232.0 million initiallyborrowed under our new Credit Facility discussed in Note 7;

·       Borrowingsof $170.0 million under our new Term Loan Facility discussed inNote 7; and

·       Netproceeds from a $174.0 million private placement of equity to certain privateinvestors discussed in Note 9.

Thefollowing is an estimate of the purchase price for the ScissorTail Acquisition(in thousands):

| Purchase price  for ScissorTail membership interests  |   | $      | 500,000 |   |
|-------------------------------------------------------|--------|--------|---------|--------|
| Estimated net  working capital adjustments            |   | (4,735 | )       |
| Estimated  acquisition costs                          |   | 3,870  |    |
| Total purchase  price for the ScissorTail Acquisition |   | $      | 499,135 |   |

 

Withthe assistance of a third party valuation firm, our management has prepared apreliminary assessment of the fair value of the property, plant and equipmentand intangible assets of ScissorTail as of August 1, 2005. Using thepreliminary assessment, the purchase price has been allocated as of August 1,

F-16

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

2005 as presented below (in thousands). We do notanticipate any material adjustments to this preliminary purchase priceallocation.

| Cash and cash  equivalents            |   | $       | 19,847  |   |
|---------------------------------------|--------|---------|---------|--------|
| Accounts  receivable                  |   | 28,265  |    |
| Prepayments and  other current assets |   | 1,817   |    |
| Property, plant  and equipment        |   | 414,003 |    |
| Intangibles                           |   | 95,134  |    |
| Other assets                          |   | 2,090   |    |
| Accounts payable                      |   | (36,483 | )       |
| Other current  liabilities            |   | (25,538 | )       |
|                                  |   | $       | 499,135 |   |

 

All liabilities assumed were at their fair values. Thefair value of intangibles is estimated to be $95,134,000, which includes$42,444,000 of contracts with a weighted average amortization period of 15years and $52,690,000 of right-of-ways and easements with a weighted averageamortization period of 25 years. There were no identified intangibles whichwere determined to have indefinite lives. See Note 2.

F-17

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Thefollowing table presents selected unaudited pro forma financial informationincorporating the historical (pre-acquisition) results of ScissorTail as if theScissorTail Acquisition had occurred at the beginning of each of the periodspresented as opposed to the actual date that the acquisition occurred. Excludedfrom the pro forma financial information are certain non-recurring charges of$1.9 million and $0.7 million for the years ended December 31,2005 and 2004, respectively, related to the write-off of the remaining debtissuance costs related to senior indebtedness existing prior to the ScissorTailAcquisition. The pro forma information is based upon preliminary data currentlyavailable and includes certain estimates and assumptions made by management. Asa result, this preliminary information is not necessarily indicative of ourfinancial results had the transactions actually occurred at the beginning ofeach of the periods presents. Likewise, the following unaudited pro formafinancial information is not necessarily indicative of our future financialresults.

| ** **                                      | ** ** | **Year Ended December 31,**                                 | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------------------------------|------------|
| ** **                                      | ** ** | **2005**                                                                   | ** ** | **2004** | ** ** |
| ** **                                      | ** ** | **(unaudited, in thousands  except unit information)** | ** ** |
| Pro Forma  Earnings Data:                       |       |                                                                       |       |   |   |
| Revenue                                         |       | $                                                                          | 933,030    |   | $ | 689,881 |   |
| Costs and expenses                              |       | $                                                                          | 866,972    |   | $ | 656,348 |   |
| Operating income                                |       | $                                                                          | 66,058     |   | $ | 33,534 |   |
| Income (loss) before extraordinary items        |       | $                                                                          | 34,825     |   | $ | (1,574 | ) |
| Net income (loss)                               |       | $                                                                          | 34,825     |   | $ | (1,574 | ) |
| Basic net income  (loss) per equivalent unit:   |       |                                                                       |       |   |   |
| As reported equivalent units outstanding        |       | 9,643                                                                      |       | 2,599 |   |
| Pro forma units outstanding                     |       | 13,241                                                                     |       | 16,761 |   |
| As reported net income (loss) per unit          |       | $                                                                          | 2.31       |   | $ | (0.35 | ) |
| Pro forma net income (loss) per unit            |       | $                                                                          | 2.08       |   | $ | (0.09 | ) |
| Diluted net  income (loss) per equivalent unit: |       |                                                                       |       |   |   |
| As reported equivalent units outstanding        |       | 13,254                                                                     |       | 2,604 |   |
| Pro forma units outstanding                     |       | 16,852                                                                     |       | 16,761 |   |
| As reported net income (loss) per unit          |       | $                                                                          | 2.29       |   | $ | (0.35 | ) |
| Pro forma net  income (loss) per unit           |       | $                                                                          | 2.07       |   | $ | (0.09 | ) |

 

*Karnes and RungeGathering Systems*

In August 2004, we acquired the Karnes County GatheringSystem from Gulf South Pipeline Company, L.P. located in northern Bee andsouthern Karnes Counties, Texas, for approximately $305,000, which includes$200,000 cash to the seller and $105,000 related to legal and due diligencecosts.

In December 2004, we acquired the Runge GatheringSystem located in Bee, Goliad, Karnes and DeWitt Counties, Texas from KinderMorgan Texas Pipeline, L.P. (“KMTP”). This acquisition was accomplished at nocost to us (other than $59,000 of legal and due diligence transaction costs) bydedicating the natural gas supplies connected and flowing into the Rungegathering system prior to October 1, 2004 to KMTP for purchase under along term agreement at a purchase price favorable to KMTP. We assigned a valueof $509,000 to the system and the long term supply agreement based on thepresent value of future cash flows of the existing contracts discounted at 12%.This amount was set up as deferred revenue which is included in risk managementand other noncurrent liabilities on the 

F-18

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

consolidated balancesheets and is being amortized on a straight-line basis to natural gas salesover 20 years.

Our management allocatedthe purchase price of these asset acquisitions entirely to property, plant andequipment. No pro forma financial information is included as to do so would notbe meaningful.

**Note 5—Property,Plant, Equipment and Asset Retirement Obligations**

Property,plant and equipment consisted of the following (in thousands):

| ** **                                      | ** ** | **December 31,** | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|
| ** **                                      | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Property, plant  and equipment, at cost         |       |                  |       |   |   |
| Pipelines and equipment                         |       | $                     | 510,209    |   | $ | 93,393 |   |
| Gas processing plant and equipment              |       | 50,564                |       | 48,711 |   |
| Construction in progress                        |       | 8,445                 |       | 1,349 |   |
| Office furniture and equipment                  |       | 2,617                 |       | 1,933 |   |
|                                            |       | 571,835               |       | 145,386 |   |
| Less accumulated  depreciation and amortization |       | (39,515               | )          | (25,703 | ) |
| Property, plant  and equipment, net             |       | $                     | 532,320    |   | $ | 119,683 |   |

 

*Assetretirement obligations.*   We have recorded assetretirement obligations related to those (i) rights-of-way and easementsover property we do not own and (ii) regulatory requirements where a legal or contractual obligation existsupon abandonment of the related facility. In December 2005, weadopted FIN 47 and recorded a $215,000 liability in connection withconditional asset retirement obligations. The cumulative effect of this changein accounting principle for years prior to 2005 was not significant. None ofour assets are legally restricted for purposes of settling asset retirementobligations.

Thefollowing table presents information regarding our asset retirement obligations(in thousands).

| Asset retirement  obligation liability balance, December 31, 2004 |   | $   | — |   |
|------------------------------------------------------------------------|--------|-----|--------|--------|
| Adoption of FIN  47 for conditional obligations                        |   | 215 |   |
| Asset retirement  obligation liability balance, December 31, 2005 |   | $   | 215    |   |

 

Property and equipment at December 31, 2005 and2004 includes $119,000 and $0, respectively, of asset retirement costscapitalized as an increase in the associated long-lived asset. Also, based oninformation currently available, we estimate that accretion expense willapproximate $15,000 for 2006, $16,000 for 2007, $17,000 for 2008, $19,000 for2009 and $20,000 for 2010.

F-19

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

For the periods indicated,the following table shows unaudited pro forma net income (loss) for the yearsended December 31, 2005, 2004 and 2003, assuming the adoption ofFIN 47 were applied retroactively to January 1, 2003.

| ** **                                                      | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                      | ** ** | **2005**              | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                      | ** ** | **(in thousands)**    | ** ** |
| Net income  (loss)—as reported                             |       | $                     | 30,352     |   | $ | (915 | ) | $ | (4,717 | ) |
| Effect of  implementation of FIN 47                        |       | 126                   |       | (13 | ) | (12 | ) |
| Less net income  attributable to subordinated unitholders       |       | (8,148                | )          | — |   | — |   |
| Net income  (loss)—basic—pro forma                    |       | 22,330                |       | (928 | ) | (4,729 | ) |
| Net income  attributable to subordinated unitholders            |       | 8,148                 |       | — |   | — |   |
| Accretion of  preferred units                                   |       | —                |       | — |   | (743 | ) |
| Cash  distributions to preferred unitholders                    |       | —                |       | — |   | (810 | ) |
| Payment in kind  distributions to pre-IPO preferred unitholders |       | —                |       | — |   | (2,453 | ) |
| Net income (loss)  available—diluted—pro forma        |       | $                     | 30,478     |   | $ | (928 | ) | $ | (8,735 | ) |
| Basic weighted  average equivalent units                        |       | 9,643                 |       | 2,599 |   | 1,405 |   |
| Dilutive weighted  average equivalent units                     |       | 13,254                |       | 2,604 |   | 1,405 |   |
| Basic net income  (loss) per equivalent unit—as reported   |       | $                     | 2.31       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Basic net income  (loss) per equivalent unit—pro forma     |       | $                     | 2.32       |   | $ | (0.36 | ) | $ | (6.22 | ) |
| Diluted net  income (loss) per equivalent unit—as reported |       | $                     | 2.29       |   | $ | (0.35 | ) | $ | (6.21 | ) |
| Diluted net income  (loss) per equivalent unit—pro forma   |       | $                     | 2.30       |   | $ | (0.36 | ) | $ | (6.22 | ) |

 

Certain of ourunconsolidated affiliates have AROs recorded at December 31, 2005 relatingto contractual agreements and regulatory requirements. These amounts areimmaterial to our consolidated financial statements.

**Note 6—Investmentin Unconsolidated Affiliates**

We, through a wholly-owned subsidiary, hold a 62.5%general partnership interest in Webb Duval and are the operator of Webb Duval’snatural gas gathering systems located in Webb and Duval Counties, Texas. Althoughwe own a majority interest in Webb Duval and operate Webb Duval, we use theequity method of accounting for its investment in Webb Duval because the termsof the general partnership agreement of Webb Duval provide the minority generalpartners substantive participating rights with respect to the management ofWebb Duval. The investment in Webb Duval, an unconsolidated affiliate, totaled$5,186,000 and $4,371,000 as of December 31, 2005 and 2004, respectively. Asof December 31, 2005 and 2004, the investment in Webb Duval was carried at$241,000 and $250,000, respectively, less than the amount of the underlyingequity in net assets (4% and 5%, respectively, of total investment ofunconsolidated affiliates). This difference is being amortized into income on astraight-line basis over the life of the underlying related property andequipment of Webb Duval. Equity in earnings (loss) from unconsolidatedaffiliates is included in income from operations as the operations of WebbDuval are integral to us.

In connection with the ScissorTail Acquisition, we,through ScissorTail, now operate and hold a majority interest in Southern Domein partnership with the prior ScissorTail ownership group. Southern Dome wasformed to engage in the midstream gas gathering and processing business andrelated operations in Oklahoma County, Oklahoma. Although we own a majorityinterest in Southern Dome, we 

F-20

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

account for our investmentusing the equity method of accounting because the minority members have substantiveparticipating rights with respect to the management of Southern Dome. Theinvestment in Southern Dome, an unconsolidated affiliate, totaled $2,715,000 asof December 31, 2005.

The summarized financialinformation for significant investment in unconsolidated affiliates, which areaccounted for using the equity method, is as follows (in thousands):

**Webb/DuvalGatherers**

**SummaryHistorical Financial Information**

| ** **                                                                                          | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Operating revenue                                                                                   |       | $                                          | 6,809      |   | $ | 4,605 |   | $ | 3,180 |   |
| Operating  expenses                                                                                 |       | (4,837                                     | )          | (3,504 | ) | (3,017 | ) |
| Depreciation                                                                                        |       | (702                                       | )          | (655 | ) | (591 | ) |
| Net income (loss)                                                                                   |       | 1,270                                      |       | 446 |   | (428 | ) |
| Ownership%                                                                                          |       | 62.5                                       | %          | 62.5 | % | 62.5 | % |
|                                                                                                |       | 794                                        |       | 278 |   | (268 | ) |
| CWDPL share of  management fee charged to Webb Duval                                                |       | 120                                        |       | 120 |   | 120 |   |
| Amortization of  difference between the carried investment and the underlying equity in net  assets |       | 21                                         |       | 21 |   | 21 |   |
| Equity in  earnings (loss) from unconsolidated affiliate                                            |       | $                                          | 935        |   | $ | 419 |   | $ | (127 | ) |
| Distributions  from unconsolidated affiliate                                                        |       | $                                          | —     |   | $ | — |   | $ | — |   |
| Current assets                                                                                      |       | $                                          | 3,378      |   | $ | 2,348 |   |   |   |
| Noncurrent assets                                                                                   |       | 8,032                                      |       | 8,283 |   |   |   |
| Current  liabilities                                                                                |       | (2,701                                     | )          | (3,237 | ) |   |   |
| Noncurrent  liabilities                                                                             |       | (44                                        | )          | — |   |   |   |
| Net assets                                                                                          |       | $                                          | 8,665      |   | $ | 7,394 |   |   |   |

 

**Note 7—Long-Term Debt**

Asummary of our debt follows (in thousands):

| ** **           | ** ** | **December 31,** | ** ** |
|----------------------|------------|-----------------------|------------|
| ** **           | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Long-term  debt:     |       |                  |       |   |   |
| Credit Facility      |       | $                     | 228,000    |   | $ | — |   |
| Term Loan Facility   |       | 170,000               |       | — |   |
| CPG Credit Agreement |       | —                |       | 48,000 |   |
| CHC Facility         |       | —                |       | 9,000 |   |
| Total                |       | $                     | 398,000    |   | $ | 57,000 |   |

 

*Credit Facility*

On August 1, 2005, we entered into a new $350million senior secured revolving credit facility (the “Credit Facility”) withBank of America, N.A., as Administrative Agent, and a group of financialinstitutions, as lenders. Our Credit Facility includes a $25 millionsublimit for the issuance of standby 

F-21

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

letters of credit andmatures on July 31, 2010. In January 2006, we amended the CreditFacility to, among other things, increase the amount of unsecured indebtednesspermitted to refinance the Term Loan Facility discussed below.

On August 1, 2005, we borrowed $232,000,000 underour Credit Facility to: (i) partially finance the ScissorTail Acquisitiondiscussed in Note 4 and (ii) to repay in full indebtednessoutstanding under the CPG Credit Agreement and the CHC Facility discussed below.Additionally, in connection with the ScissorTail Acquisition, we assumed astandby letter of credit of $900,000, which remains outstanding at December 31,2005. Future borrowings under the Credit Facility are available foracquisitions, capital expenditures, working capital and general corporatepurposes. The Credit Facility does not provide for the type of working capitalborrowings that would be eligible, pursuant to our limited liability companyagreement, to be considered cash available for distribution to unitholders. TheCredit Facility is available to be drawn on and repaid without restriction solong as we are in compliance with the terms of the Credit Facility, includingcertain financial covenants.

The Credit Facility contains various covenants thatlimit us and certain of our operating subsidiaries’ ability to grant certainliens; make certain loans and investments; make certain capital expendituresoutside our current lines of business or certain related lines of business;make distributions other than from available cash (as defined in our limitliability company agreement); merge or consolidate with or into a third party;or engage in certain asset dispositions, including a sale of all orsubstantially all of our assets. Additionally, our Credit Facility limits usand certain of our operating subsidiaries’ ability to incur additionalindebtedness with certain exceptions, including under the Term Loan Facility(as discussed below), purchase money indebtedness and indebtedness related tocapital or synthetic leases not to exceed $5.0 million, unsecured indebtednessnot to exceed $5.0 million and unsecured indebtedness qualifying assubordinated debt.

The Credit Facilityalso contains covenants, which, among other things, requires us and certain ofour subsidiaries, on a consolidated basis, to maintain specified ratios orconditions as follows:

·       EBITDAto interest expense of not less than 2.5 to 1.0 through September 30,2005, 2.75 to 1.0 from December 31, 2005 through June 30, 2006 and3.0 to 1.0 thereafter;

·       EBITDAminus maintenance capital expenditures to consolidated fixed charges of notless than 1.5 to 1.0 through September 30, 2005 and 1.75 to 1.0thereafter;

·       totaldebt to EBITDA of not more than 5.5 to 1.0 through September 30, 2005, 5.0to 1.0 from December 31, 2005 through June 30, 2006 and 4.75 to 1.0thereafter; and

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0 through September 30,2005 and 3.5 to 1.0 thereafter.

EBITDA for the purposes of the Credit Facility is ourEBITDA with certain negotiated adjustments.

Based upon the senior debt to EBITDA ratio calculatedas of December 31, 2005 (utilizing trailing four quarters’ EBITDA asdefined under our Credit Facility), we have approximately $122.0 millionof unused capacity under the Credit Facility.

The obligations under the Credit Facility are securedby first priority liens on substantially all of our assets and substantiallyall of the assets of our subsidiaries (other than Webb Duval, Southern Dome andcertain subsidiaries with insignificant assets). Additionally, the obligationsunder the Credit Facility are 

F-22

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

guaranteed bysubstantially all of our subsidiaries (other than Webb Duval, Southern Dome andcertain subsidiaries with insignificant assets).

At our election, interest under the Credit Facility isdetermined by reference to (i) the British Bankers Association LIBOR rate,or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum or (ii) thehigher of the federal funds rate plus 0.5% or the prime rate plus, in eithercase, an applicable margin between 0.25% and 1.25% per annum. Interest ispayable quarterly for prime rate loans and at the applicable maturity date forLIBOR loans, except that if the interest period for a LIBOR loan is six months,interest will be paid at the end of each three-month period.

If an event ofdefault exists under the Credit Facility, the lenders may accelerate thematurity of the obligations outstanding under the Credit Facility and exerciseother rights and remedies. Each of the following would be an event of default:

·       failureto pay any principal when due or any interest, fees or other amount withincertain grace periods;

·       failureto perform or otherwise comply with the covenants in the credit agreement orother loan documents, subject, in certain instances, to certain grace periods;

·       defaulton the payment of any other indebtedness in excess of $5.0 million or anydefault in the performance of any obligation or condition with respect to suchindebtedness beyond the applicable grace period if the effect of the default isto permit or cause the acceleration of the indebtedness;

·       bankruptcyor insolvency events involving us or our subsidiaries;

·       theentry of, and failure to pay, one or more adverse judgments in excess of $5.0million against which enforcement proceedings are brought or that are notstayed pending appeal; and

·       achange of control (as defined in the Credit Facility).

The effective average interest rate on borrowingsunder the Credit Facility was 6.15% and the quarterly commitment fee on theunused portion of the Credit Facility was 0.25% as of December 31, 2005. Interestand other financing costs related to the Credit Facility totaled $6,572,000 forthe period from August 1, 2005 through December 31, 2005. Costs incurredin connection with the establishment of this credit facility are beingamortized over the term of the Credit Facility, and as of December 31,2005, the unamortized portion of debt issue costs totaled $4,749,000.

Our management believes that we are in compliance withthe covenants under the Credit Facility as of December 31, 2005.

F-23

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*Term Loan Facility*

On August 1, 2005, we entered into a $170,000,000senior unsecured term loan facility (the “Term Loan Facility”) with Banc ofAmerica Bridge LLC, as the Lender. The proceeds from the Term Loan Facilitywere used to pay a portion of the purchase price of the ScissorTail Acquisition.In January 2006, we used $20,000,000 of proceeds from our privateplacement of equity (discussed in Note 9) to pay down the balance of theTerm Loan Facility to $150,000,000. In February 2006, we used proceeds fromthe issuance of Senior Notes due 2016 to repay and terminate the Term LoanFacility. Please read *“Senior Notes Offering”*below.

The effective average interest rate on borrowingsunder the Term Loan Facility was 9.29% as of December 31, 2005. Interestand other financing costs related to the Term Loan Facility totaled $9,891,000for the period from August 1, 2005 through December 31, 2005. Weincurred costs in connection with the establishment of this credit facilitythat are being amortized over the estimated term of the Term Loan Facility, andas of December 31, 2005, the unamortized portion of debt issue coststotaled $584,000.

Our management believesthat we were in compliance with the covenants under the Term Loan Facility asof December 31, 2005.

*Senior NotesOffering*

On February 7, 2006, we closed the privateplacement of an aggregate of $225 million in principal amount of our8.125% senior notes due 2016 (the “Senior Notes”) in a transaction exempt fromthe registration requirements under the Securities Act of 1933. We used the netproceeds from the issuance of the Senior Notes of $219,375,000 to (i) repayand terminate our Term Loan Facility discussed above, (ii) reduce thebalance outstanding under our Credit Facility by $68,000,000 and (iii) payexpenses of approximately $1,375,000.

The Senior Notes represent our senior unsecuredobligations and rank pari passu in right of payment with all our other presentand future senior indebtedness. The Senior Notes are effectively subordinatedto all of our secured indebtedness to the extent of the value of the assetssecuring the indebtedness and to all existing and future indebtedness andliabilities, including trade payables, of our non-guarantor subsidiaries (otherthan indebtedness and other liabilities owed to us, if any). The Senior Notesrank senior in right of payment to all of our future subordinated indebtedness.

The Senior Notes are jointly and severally guaranteedby all of our current wholly-owned subsidiaries (other than CEFC, the co-issuerof the Senior Notes) and by certain of our future subsidiaries. The subsidiaryguarantees rank equally in right of payment with all of the existing and futuresenior indebtedness of our guarantor subsidiaries, including their guaranteesof our other senior indebtedness. The subsidiary guarantees are effectivelysubordinated to all existing and future secured indebtedness of our guarantorsubsidiaries to the extent of the value of the assets securing thatindebtedness and to all existing and future indebtedness and other liabilities,including trade payables, of any non-guarantor subsidiaries (other thanindebtedness and other liabilities owed to our guarantor subsidiaries). Thesubsidiary guarantees rank senior in right of payment to any futuresubordinated indebtedness of our guarantor subsidiaries.

Before March 1, 2009, we may, at any time or fromtime to time, redeem up to 35% of the aggregate principal amount of the SeniorNotes with the net proceeds of a public or private equity offering at 108.125%of the principal amount of the Senior Notes, plus any accrued and unpaidinterest, if at least 

F-24

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

65% of the aggregateprincipal amount of the notes remains outstanding after such redemption and theredemption occurs within 120 days of the date of the closing of such equityoffering.

TheSenior Notes are redeemable, at our option, in whole or in part, at any time onor after March 1, 2011, in each case at the redemption prices described inthe table below, together with any accrued and unpaid interest to the date ofthe redemption.

| **Year**            | ** ** | ** ** | ** ** | **Percentage** | ** ** |
|---------------------|------------|------------|------------|----------------|------------|
| 2011                |       |       | 104.0625   | %              |       |
| 2012                |       |       | 102.7083   | %              |       |
| 2013                |       |       | 101.3542   | %              |       |
| 2014 and thereafter |       |       | 100.0000   | %              |       |

 

The indenturegoverning the Senior Notes contains covenants that, among other things, limitour ability and the ability of our restricted subsidiaries to:

·       sellassets;

·       paydistributions on, redeem or repurchase our units or redeem or repurchase oursubordinated debt;

·       makeinvestments;

·       incuror guarantee additional indebtedness or issue preferred units;

·       createor incur certain liens;

·       enterinto agreements that restrict distributions or other payments from ourrestricted subsidiaries to us;

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

·       engagein transactions with affiliates;

·       createunrestricted subsidiaries; and

·       enterinto sale and leaseback transactions.

These covenants are subject to important exceptionsand qualifications and, additionally, if the Senior Notes achieve an investmentgrade rating from each of Moody’s Investors Service, Inc. and Standard &Poor’s Ratings Services, many of these covenants will terminate.

We have agreed to conduct a registered exchange offerfor the Senior Notes or to cause to become effective a shelf registrationstatement providing for resales of the Senior Notes. If we fail to satisfythese obligations on a timely basis, we have agreed to pay additional interestto holders of the Senior Notes under some circumstances.

Condensed consolidating financial information forCopano and our wholly-owned subsidiaries is presented below. Separate financialstatements of our guarantor subsidiaries are not provided because we do notbelieve that such information would be material to our investors or lenders.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

**CONDENSED CONSOLIDATING BALANCE SHEET—DECEMBER 31,2005**

| ** **                                                                                                                                    | ** ** | **Parent**              | ** ** | **Co-Issuer** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------|------------|---------------|------------|-----------------------------|------------|------------------|------------|-----------|------------|
| ** **                                                                                                                                    | ** ** | **(in thousands)** | ** ** |
| **ASSETS**                                                                                                                                    |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Current assets:                                                                                                                               |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Cash and cash equivalents                                                                                                                     |       | $                       | 1,167      |          |       | $                           | 1          |             |       |      | $          | 24,129 |   |   |   | $ | — |   |   | $ | 25,297 |   |
| Accounts receivable, net                                                                                                                      |       | —                  |       |          | —     |                        |       |             | 83,297     |      |       |   | — |   |   | 83,297 |   |
| Intercompany receivable                                                                                                                       |       | 35,040                  |       |          | —     |                        |       |             | 12,525     |      |       |   | (47,565 | ) |   | — |   |
| Risk management assets                                                                                                                        |       | —                  |       |          | —     |                        |       |             | 10,067     |      |       |   | — |   |   | 10,067 |   |
| Prepayments and other current assets                                                                                                          |       | 44                      |       |          | —     |                        |       |             | 2,430      |      |       |   | — |   |   | 2,474 |   |
| Total current assets                                                                                                                          |       | 36,251                  |       |          | 1          |                        |       |             | 132,448    |      |       |   | (47,565 | ) |   | 121,135 |   |
| Property, plant and equipment, net                                                                                                            |       | 363                     |       |          | —     |                        |       |             | 531,957    |      |       |   | — |   |   | 532,320 |   |
| Intangible assets,  net                                                                                                                       |       | —                  |       |          | —     |                        |       |             | 97,551     |      |       |   | — |   |   | 97,551 |   |
| Investment in  unconsolidated affiliates                                                                                                      |       | —                  |       |          | —     |                        |       |             | 7,901      |      |       |   | — |   |   | 7,901 |   |
| Investment in  consolidated subsidiaries                                                                                                      |       | 605,871                 |       |          | —     |                        |       |             | —     |      |       |   | (605,871 | ) |   | — |   |
| Risk management  assets                                                                                                                       |       | —                  |       |          | —     |                        |       |             | 24,778     |      |       |   | — |   |   | 24,778 |   |
| Other assets, net                                                                                                                             |       | 6,004                   |       |          | —     |                        |       |             | 3,061      |      |       |   | — |   |   | 9,065 |   |
| Total assets                                                                                                                                  |       | $                       | 648,489    |          |       | $                           | 1          |             |       |      | $          | 797,696 |   |   |   | $ | (653,436 | ) |   | $ | 792,750 |   |
| **LIABILITIES  AND MEMBERS’ CAPITAL**                                                                                                    |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Current liabilities:                                                                                                                          |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Accounts payable                                                                                                                              |       | $                       | 165        |          |       | $                           | —     |             |       |      | $          | 95,836 |   |   |   | $ | — |   |   | $ | 96,001 |   |
| Accounts payable to affiliates                                                                                                                |       | —                  |       |          | —     |                        |       |             | 189        |      |       |   | — |   |   | 189 |   |
| Intercompany payable                                                                                                                          |       | 3,981                   |       |          | —     |                        |       |             | 43,584     |      |       |   | (47,565 | ) |   | — |   |
| Notes payable                                                                                                                                 |       | —                  |       |          | —     |                        |       |             | 1,272      |      |       |   | — |   |   | 1,272 |   |
| Other current liabilities                                                                                                                     |       | 5,694                   |       |          | —     |                        |       |             | 5,276      |      |       |   | — |   |   | 10,970 |   |
| Total current liabilities                                                                                                                     |       | 9,840                   |       |          | —     |                        |       |             | 146,157    |      |       |   | (47,565 | ) |   | 108,432 |   |
| Long-term debt                                                                                                                                |       | 398,000                 |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 398,000 |   |
| Risk management  and other noncurrent liabilities                                                                                             |       | 262                     |       |          | —     |                        |       |             | 4,253      |      |       |   | — |   |   | 4,515 |   |
| Members’/Partners’  capital:                                                                                                        |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Common units, no par value, 14,100,508 units and  7,056,252 units issued and outstanding as of December 31, 2005 and 2004,  respectively |       | 297,592                 |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 297,592 |   |
| Subordinated units, no par value, 3,519,126 units  issued and outstanding as of December 31, 2005 and 2004                               |       | 10,379                  |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 10,379 |   |
| Paid-in capital                                                                                                                               |       | 4,068                   |       |          | 1          |                        |       |             | 585,800    |      |       |   | (585,801 | ) |   | 4,068 |   |
| Accumulated deficit                                                                                                                           |       | (67,703                 | )          |          | —     |                        |       |             | 72,832     |      |       |   | (20,070 | ) |   | (14,941 | ) |
| Deferred compensation                                                                                                                         |       | (3,949                  | )          |          | —     |                        |       |             | —     |      |       |   | — |   |   | (3,949 | ) |
| Other comprehensive loss                                                                                                                      |       | —                  |       |          | —     |                        |       |             | (11,346    | )         |       |   | — |   |   | (11,346 | ) |
|                                                                                                                                          |       | 240,387                 |       |          | 1          |                        |       |             | 647,286    |      |       |   | (605,871 | ) |   | 281,803 |   |
| Total liabilities  and members’/partners’ capital                                                                                   |       | $                       | 648,489    |          |       | $                           | 1          |             |       |      | $          | 797,696 |   |   |   | $ | (653,436 | ) |   | $ | 792,750 |   |

 

F-26

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

**CONDENSEDCONSOLIDATING STATEMENT OF OPERATIONS—FOR THE YEAR ENDED DECEMBER 31, 2005**

| ** **                                        | ** ** | **Parent**              | ** ** | **Co-Issuer** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|-------------------------|------------|---------------|------------|-----------------------------|------------|------------------|------------|-----------|------------|
| ** **                                        | ** ** | **(in thousands)** | ** ** |
| Revenue:                                          |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Natural gas sales                                 |       | $                       | —     |          |       | $                           | —     |             |       |      | $          | 496,906 |   |   |   | $ | — |   |   | $ | 496,906 |   |
| Natural gas liquids sales                         |       | —                  |       |          | —     |                        |       |             | 224,695    |      |       |   | — |   |   | 224,695 |   |
| Transportation, compression and processing fees   |       | —                  |       |          | —     |                        |       |             | 15,110     |      |       |   | — |   |   | 15,110 |   |
| Other                                             |       | —                  |       |          | —     |                        |       |             | 11,032     |      |       |   | — |   |   | 11,032 |   |
| Total revenue                                     |       | —                  |       |          | —     |                        |       |             | 747,743    |      |       |   | — |   |   | 747,743 |   |
| Costs and expenses:                               |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Cost of natural gas and natural gas liquids       |       | —                  |       |          | —     |                        |       |             | 641,315    |      |       |   | — |   |   | 641,315 |   |
| Transportation                                    |       | —                  |       |          | —     |                        |       |             | 2,337      |      |       |   | — |   |   | 2,337 |   |
| Operations and maintenance                        |       | 66                      |       |          | —     |                        |       |             | 18,393     |      |       |   | — |   |   | 18,459 |   |
| Depreciation and amortization                     |       | 66                      |       |          | —     |                        |       |             | 16,986     |      |       |   | — |   |   | 17,052 |   |
| General and administrative                        |       | 5,486                   |       |          | —     |                        |       |             | 12,670     |      |       |   | — |   |   | 18,156 |   |
| Taxes other than income                           |       | —                  |       |          | —     |                        |       |             | 1,178      |      |       |   | — |   |   | 1,178 |   |
| Equity in earnings from unconsolidated affiliates |       | —                  |       |          | —     |                        |       |             | (927       | )         |       |   | — |   |   | (927 | ) |
| Total costs and expenses                          |       | 5,618                   |       |          | —     |                        |       |             | 691,952    |      |       |   | — |   |   | 697,570 |   |
| Operating income (loss)                           |       | (5,618                  | )          |          | —     |                        |       |             | 55,791     |      |       |   | — |   |   | 50,173 |   |
| Other income (expense):                           |       |                    |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Interest and other income                         |       | 3                       |       |          | —     |                        |       |             | 1,023      |      |       |   | (386 | ) |   | 640 |   |
| Interest and other financing costs                |       | (16,848                 | )          |          | —     |                        |       |             | (3,999     | )         |       |   | 386 |   |   | (20,461 | ) |
| Net income (loss)                                 |       | $                       | (22,463    | )             |       | $                           | —     |             |       |      | $          | 52,815 |   |   |   | $ | — |   |   | $ | 30,352 |   |

 

F-27

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS—FORTHE YEAR ENDED DECEMBER 31, 2005**

| ** **                                                        | ** ** | **Parent**          | ** ** | **Co-Issuer** | ** ** | **Guarantor  Subsidiaries** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-------------------------------------------------------------------|------------|---------------------|------------|---------------|------------|-----------------------------|------------|------------------|------------|-----------|------------|
| ** **                                                        | ** ** | **(in  thousands)** | ** ** |
| Cash Flows From  Operating Activities:                            |       |                |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Net cash (used in) provided by operating activities               |       | $                   | (47,292    | )             |       | $                           | —     |             |       |      | $          | 47,572 |   |   |   | $ | — |   |   | $ | 280 |   |
| Cash Flows From  Investing Activities:                            |       |                |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Additions to property, plant and equipment and  intangible assets |       | —              |       |          | —     |                        |       |             | (10,054    | )         |       |   | — |   |   | (10,054 | ) |
| Acquisitions, net of cash acquired                                |       | —              |       |          | —     |                        |       |             | (479,288   | )         |       |   | — |   |   | (479,288 | ) |
| Investment in unconsolidated affiliates                           |       | —              |       |          | —     |                        |       |             | (2,722     | )         |       |   | — |   |   | (2,722 | ) |
| Investment in consolidated subsidiaries                           |       | (548,662            | )          |          | —     |                        |       |             | —     |      |       |   | 548,662 |   |   | — |   |
| Distributions from consolidated subsidiaries                 |       | 48,024              |       |          | —     |                        |       |             | —     |      |       |   | (48,024 | ) |   | — |   |
| Other                                                             |       | —              |       |          | —     |                        |       |             | 356        |      |       |   | — |   |   | 356 |   |
| Net cash used in investing activities                             |       | (500,638            | )          |          | —     |                        |       |             | (491,708   | )         |       |   | 500,638 |   |   | (491,708 | ) |
| Cash Flows From  Financing Activities:                            |       |                |       |          |       |                        |       |             |       |      |       |   |   |   |   |   |   |
| Repayments of long-term debt                                      |       | (37,000             | )          |          | —     |                        |       |             | (57,000    | )         |       |   | — |   |   | (94,000 | ) |
| Proceeds from long-term debt                                      |       | 435,000             |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 435,000 |   |
| Deferred financing costs                                          |       | (9,735              | )          |          | —     |                        |       |             | (67        | )         |       |   | — |   |   | (9,802 | ) |
| Repayment of short-term notes payable                             |       | —              |       |          | —     |                        |       |             | (1,207     | )         |       |   | — |   |   | (1,207 | ) |
| Distributions to unitholders                                      |       | (23,366             | )          |          | —     |                        |       |             | —     |      |       |   | — |   |   | (23,366 | ) |
| Proceeds from private placement of common units                   |       | 64,499              |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 64,499 |   |
| Proceeds from private placement of Class B  units            |       | 135,503             |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 135,503 |   |
| Capital contributions from Pre-Offering Investors                 |       | 4,068               |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 4,068 |   |
| Equity offering costs                                             |       | (1,074              | )          |          | —     |                        |       |             | —     |      |       |   | — |   |   | (1,074 | ) |
| Proceeds from option exercises                                    |       | 89                  |       |          | —     |                        |       |             | —     |      |       |   | — |   |   | 89 |   |
| (Repayment of) proceeds from of intercompany of debt              |       | (19,011             | )          |          | —     |                        |       |             | 19,011     |      |       |   | — |   |   | — |   |
| Contributions from parent                                         |       | —              |       |          | 1          |                        |       |             | 548,661    |      |       |   | (548,662 | ) |   | — |   |
| Distributions to parent                                           |       | —              |       |          | —     |                        |       |             | (48,024    | )         |       |   | 48,024 |   |   | — |   |
| Net cash provided by (used in) financing activities               |       | 548,973             |       |          | 1          |                        |       |             | 461,374    |      |       |   | (500,638 | ) |   | 509,710 |   |
| Net increase in cash and cash equivalents                         |       | 1,043               |       |          | 1          |                        |       |             | 17,238     |      |       |   | — |   |   | 18,282 |   |
| Cash and cash  equivalents, beginning of year                     |       | 124                 |       |          | —     |                        |       |             | 6,891      |      |       |   | — |   |   | 7,015 |   |
| Cash and cash  equivalents, end of year                           |       | $                   | 1,167      |          |       | $                           | 1          |             |       |      | $          | 24,129 |   |   |   | $ | — |   |   | $ | 25,297 |   |

 

F-28

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

*CPG CreditAgreement*

Prior to the consummation of the Credit Facilitydiscussed above, we, through our wholly-owned Texas Gulf Coast Pipelinessubsidiaries, had a $100 million revolving credit agreement, as amended,(the “CPG Credit Agreement”), with a syndicate of commercial banks. On August 1,2005, this credit facility was paid in full and terminated using the proceedsfrom the Credit Facility.

At our election, interest under this credit facilitywas determined by reference to (1) the reserve-adjusted Londoninterbank offered rate, or LIBOR, plus an applicable margin between 1.75% and3% per annum or (2) the prime rate plus, in certain circumstances, anapplicable margin between 0.25% and 1.5% per annum. During 2005, 2004 and 2003,the effective average interest rate on borrowings under the CPG Credit Agreementwas 6.19%, 4.01% and 3.72%, respectively. A quarterly commitment fee of between0.375% and 0.5% per annum was charged on the unused portion of this creditfacility and was 0.5% at December 31, 2004.

Interest and otherfinancing costs related to our CPG Credit Agreement totaled $1,996,000,$2,971,000 and $1,181,000 for the years ended December 31, 2005, 2004 and2003, respectively. Additionally, we incurred other costs in connection withthis credit facility, which costs were being amortized over the remaining termof the CPG Credit Agreement, and as of December 31, 2004, the unamortizedportion of debt issue costs totaled $1,736,000. Effective with the earlytermination of this agreement in August 2005, we charged $1,472,000 tointerest expense, representing the balance of the unamortized debt issuancecosts.

*CHC CreditAgreement*

In November 2001, we, through our wholly-ownedTexas Gulf Coast Processing subsidiaries entered into a $35 million creditagreement (the “CHC Credit Agreement”) with a syndicate of commercial banks. InFebruary 2004, this credit facility was paid in full and terminated usingproceeds from the CPG Credit Agreement discussed above.

Interest and otherfinancing costs related to the CHC Credit Agreement totaled $446,000 and $1,488,000for the years ended December 31, 2004 and 2003, respectively. Additionally,we incurred other costs in connection with this credit facility. These costswere being amortized over the remaining term of the CHC Credit Agreement. In February 2004,effective with the early termination of this agreement, we charged $314,000 tointerest expense, representing the balance of the unamortized debt issue costs.

*CHC Facility*

Concurrent with the closing of the Offering, on November 15,2004, certain of our Texas Gulf Coast Processing subsidiaries entered into a$12 million secured revolving credit facility (the “CHC Facility”) withComerica Bank due January 31, 2007. At the closing, we borrowed $9,000,000under this facility to retire the remaining balance outstanding under the TexasGulf Coast Processing term loan. On August 1, 2005, this credit facilitywas paid in full and terminated using the proceeds from the Credit Facility.

At our election, interest under this revolving creditfacility was determined by reference to (1) the reserve-adjustedinterbank offered rate, or IBOR, plus an applicable margin between 2.5% and3.5% per annum or (2) the prime rate plus, in certain circumstances, anapplicable margin of up to 1.5% per annum. During 2005 and 2004, the effectiveaverage interest rate on borrowings under the CHC Facility was 5.11% 

F-29

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

and 4.77%, respectively. Aquarterly commitment fee of between 0.3% and 0.5% per annum was charged on theunused portion of this credit facility and was 0.3% at December 31, 2004.

Interest and otherfinancing costs related to the CHC Facility totaled $320,000 and $69,000 forthe years ended December 31, 2005 and 2004, respectively. Additionally, weincurred other costs in connection with this credit facility. These costs werebeing amortized over the term of the CHC Facility, and as of December 31,2004, the unamortized portion of debt issue costs totaled $188,000. Effectivewith the early termination of this facility in August 2005, we charged$136,000 to interest expense, representing the balance of the unamortized debtissuance costs.

*ScheduledMaturities of Long-term Debt*

Scheduledmaturities of long-term debt as of December 31, 2005 were as follows (inthousands):

| **Year**   | ** ** | ** ** | ** ** | **Principal  Amount** | ** ** |
|------------|------------|------------|------------|-----------------------|------------|
| 2006       |       | $          | —     |                  |
| 2007       |       | —     |       |
| 2008       |       | —     |       |
| 2009       |       | —     |       |
| 2010       |       | 228,000    |       |
| Thereafter |       | 170,000    |       |
|       |       | $          | 398,000    |                  |

 

**Note 8—Redeemable Preferred Units**

Through a series of transactions occurring between August 2001and November 2001, we issued redeemable preferred units in considerationfor $60,000,000 in cash. The cash proceeds from these issuances were usedprimarily to fund an asset acquisition, our acquisition of the minorityinterests in certain predecessor entities and construction costs related to ourHebbronville pipeline assets. For the first four years following the initialissuance of the preferred units, we had the right to pay the quarterlydistributions in preferred units at a 10% rate. Except for cash distributionsof $810,000 and $2,194,000 during the years ended December 31, 2003 and2002, respectively, the Board elected to pay the preferred distributions inpreferred units for all required quarterly distributions, thereby increasingthe number of preferred units and aggregated amount outstanding.

Additionally, we issued warrants to the preferredunitholders to purchase up to 3,750,000 of our common units exercisable at aprice of $16 per unit until August 14, 2011. We allocated proceeds fromthe issuance of our preferred units between the warrants and the preferredunits based on their respective fair values. The fair value of each warrant asof the date of grant was $4.34 using the Black-Scholes option pricingmodel and the following assumptions: exercise price of $16.00, expectedvolatility rate of 19%, risk-free interest rate of 4.97% and expected life of10 years. We used the Black-Scholes warrant value to assign anallocated value of $12,799,000, or $3.41 per warrant, and $47,201,000 to thepreferred units. The allocated warrant value amount was recorded as a discountagainst the redeemable preferred units and as an increase to paid-in capital. Thisdiscount was accreted as additional distributions (interest expense after theadoption of SFAS No. 150, see Note 2) through the mandatoryredemption date.

F-30

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Prior to the closing of our Offering in November 2004,the preferred unitholders exchanged these warrants for 1,211,120 common unitsand 2,091,048 subordinated units (as described in Note 9) based upon theexercise price of the warrants and the value of the underlying common unitsissued to the public. In addition, net proceeds from the Offering were used toredeem all outstanding redeemable preferred units for $78,077,000. As a resultof this redemption, we recorded additional interest expense of $7,946,000 in November 2004,which represented the write off of the remaining discount associated with theredeemable preferred units as such redemption is considered an earlyextinguishment of debt.

Additionally, we hadincurred costs in connection with the issuance of the preferred units andwarrants, including fees paid to the preferred unit purchasers, as well aslegal and other professional fees. These costs, totaling $1,704,000, wererecorded as a reduction to paid-in capital. Upon adoption of SFAS No. 150,$1,258,000, representing the amount of unamortized costs as of July 1,2003 had these costs been treated as debt issue costs from the time ofissuance, was reclassified from paid-in capital to debt issue costs and wasbeing amortized over the remaining outstanding period of the redeemable preferredunits. As a result of the 2004 redemption of the preferred units using proceedsfrom the Offering, we wrote off the unamortized balance of issuance costsassociated with the redeemable preferred units of $921,000.

**Note 9—Members’ Capital**

*Common Units, Class Band Subordinated Units After the Offering*

As of December 31, 2005, we had 14,100,508 commonunits (including 139,118 restricted common units) and 3,519,126 subordinatedunits outstanding. Management controlled an aggregate of 827,132 common unitsas of December 31, 2005. Pre-Offering Investors and their assignees ownedall of our outstanding subordinated units.

On August 1, 2005, we issued 1,372,458 commonunits in a private equity placement to certain private investors for anaggregate consideration of $39.5 million to partially fund the ScissorTailAcquisition and related costs (Note 4). In connection with the privateplacement, we granted holders of these common units certain registrationrights, and, as a result thereof, we registered these common units on aRegistration Statement on Form S-3, which was declared effective bythe Securities and Exchange Commission, or SEC, on January 26, 2006.

On August 1, 2005, we issued 4,830,758 of our Class Bunits in a private equity placement to certain private investors for anaggregate consideration of $135.5 million to partially fund the ScissorTailAcquisition and related costs (Note 4). On October 27, 2005, ourunitholders approved the conversion of each of the Class B units into onecommon unit and the issuance of 4,830,758 additional common units upon suchconversion. In connection with this private placement, we granted the formerholders of these Class B units certain registration rights, and, as aresult thereof, we registered the common units received in the conversion on aRegistration Statement on Form S-3, which was declared effective bythe SEC on January 26, 2006.

On December 29, 2005, we entered into a purchaseagreement with certain private investors for the private placement of 1,418,440of our common units for aggregate net proceeds of $50,000,000. The purchaseprice for each common unit was $35.25. Pursuant to the private placement, on December 30,2005, we issued 709,220 of our common units for aggregate proceeds of$25,000,000 and on January 3, 2006, we issued the remaining 709,220 of ourcommon units for aggregate proceeds of $25,000,000. We used the proceeds fromthe private placement to pay down balances outstanding under our CreditFacility and our Term Loan Facility discussed in Note 7. In connectionwith this private placement, we granted 

F-31

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

holders of these commonunits certain registration rights, and, as a result thereof, we will file aRegistration Statement on Form S-3 with the SEC in March 2006.

Pursuant to our limited liability company agreement,the Pre-Offering Investors agreed to reimburse us for general andadministrative expenses in excess of stated levels (subject to certainlimitations) for a period of three years beginning on January 1, 2005. Specifically,to the extent general and administrative expenses exceed certain levels, theportion of the general and administrative expenses ultimately funded by us(subject to certain adjustments and exclusions) will be limited, or capped. Forthe year ended December 31, 2005, the “cap” limits our general andadministrative expense obligations to $1.5 million per quarter (subject tocertain adjustments and exclusions). During this three-year period, thequarterly limitation on general and administrative expenses will be increasedby 10% of the amount by which EBITDA (as defined) for any quarter exceeds $5.4million. During 2005, our Pre-Offering Investors made capital contributions tous in the aggregate amount of $4,068,000 as a reimbursement of excess generaland administrative expenses for each of the first three quarters of 2005. ThePre-Offering Investors primarily used escrowed funds that we had distributed tothem prior to the Offering (the “Original Escrows”) to make these contributions.In February 2006, our Pre-Offering Investors made capital contributions tous in the aggregate amount of $1,380,000 as a reimbursement of excess generaland administrative expense for the fourth quarter of 2005. Since the OriginalEscrows were exhausted, the Pre-Offering Investors used distributions receivedfrom us as well as certain funds previously deposited in escrow in connectionwith unit transfers to make these contributions to us.

On November 15, 2004, immediately prior to thecompletion of our Offering, (i) Copano Partners L.P. (“Copano Partners”),an entity controlled by Mr. John R. Eckel, Jr., our Chairman of theBoard of Directors and Chief Executive Officer, exchanged its common units andjunior units for 763,221 common units and 1,317,733 subordinated unitsrepresenting approximately 19.71% of our outstanding units upon completion ofthe Offering including the exercise of the underwriters’ over-allotment option and(ii) two of our executive officers exchanged their common special unitsand junior special units for an aggregate of 63,911 common units and 110,345subordinated units representing approximately 1.65% of our outstanding unitsupon completion of the Offering including the exercise of the underwriters’over-allotment option. Additionally as discussed in Note 8, on November 15,2004, immediately prior to the completion of the Offering, the preferredunitholders exchanged their warrants for an aggregate of 1,211,120 common unitsand 2,091,048 subordinated units. After redemption of certain common unitsreceived by the former preferred unitholders using proceeds from theunderwriters’ exercise of the over-allotment option, the former preferredunitholders held an aggregate of 461,120 common units and 2,091,048subordinated units representing approximately 24.17% of our outstanding unitsupon completion of the Offering including the exercise of the underwriters’over-allotment option.

On November 15, 2004, we completed the Offeringby issuing 5,750,000 common units at $20.00 per common unit representing 54.46%of our outstanding units. Expenses of the Offering (including underwritingdiscounts and commissions of $8,050,000) totaled $13,170,000. After the redemptionof certain common units using net proceeds from the underwriters’over-allotment option and as of December 31, 2004, Pre-Offering Investorsowned an aggregate of 1,288,252 common units and the public owned an aggregateof 5,750,000 common units.

Oursubordinated units represent limited liability interests andholders of subordinated units exercise the rights and privileges available tounitholders under our limited liability company agreement. All 3,519,126subordinated units outstanding after the Offering and as of December 31,2005 and 2004 were 

F-32

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

held byPre-Offering Investors or their transfees and represented approximately 33% oftotal units outstanding after the Offering. Subordinated units, during thesubordination period, will generally receive quarterly cash distributions onlywhen the common units have received a minimum quarterly distribution of $0.40per unit for each quarter since the commencement of operations. Subordinatedunits will convert into common units on a one-for-one basis whenthe subordination period ends. Pursuant to our limited liability companyagreement, the subordination period will extend until the first day of anyquarter beginning after December 31, 2006 that each of the followingfinancial tests is met: (1) distributions of “available cash fromoperating surplus” (as defined) on each of the outstanding common units andsubordinated units for the two consecutive four-quarter periods immediatelypreceding that date equaled or exceeded the minimum quarterly distribution; (2) the“adjusted operating surplus” (as defined) generated during the two consecutivefour-quarter periods immediately preceding that date equaled or exceeded thesum of the minimum quarterly distributions on all outstanding common units andsubordinated units; and (3) there are no arrearages in payment of theminimum quarterly distributions on the common units.

*Restricted CommonUnits*

Restricted units are awarded under our long-termincentive plan and are common units that vest over a period of time and thatduring such time are subject to forfeiture. In addition, restricted units willvest upon a change of control, unless provided otherwise by the Compensation Committeeof our Board of Directors. Distributions made on restricted units may be subjectedto the same vesting provisions as the restricted units. The restricted unitsare intended to serve as a means of incentive compensation for performance andnot primarily as an opportunity to participate in the equity appreciation ofthe common units. Therefore, plan participants will not pay any considerationfor the common units they receive and we will receive no remuneration for theunits.

During the year ended December 31, 2005, weawarded 118,380 restricted common units to employees, including 85,998restricted units awarded at the time of the ScissorTail Acquisition toScissorTail employees. These restricted common units had an aggregate intrinsicvalue of $4,464,000. Of these restricted unit grants, 15,400 vest in equalone-third annual installments commencing on the first anniversary of the grantdate, 11,720 vest in equal one-fourth annual installments commencing on thefirst anniversary of the grant date, 91,260 vest in equal one-fifth annualinstallments commencing on the first anniversary of the grant date and all ofthese restricted units vest upon a change of control, death, disability or, incertain circumstances, retirement. Additionally, during the year ended December 31,2005, we awarded 9,000 restricted common units to our six independent directorswith an aggregate intrinsic value of $347,000. Each restricted unit grant vestsin equal one-third annual installments commencing on the first anniversary ofthe grant date or upon a change of control, death, disability or, in certaincircumstances, retirement. The aggregate intrinsic value of the units isamortized into general and administrative expense over the respective vestingperiods. We recognized non-cash compensation expense of $1,283,000 related tothe amortization of restricted units outstanding during the year ended December 31,2005.

During the year ended December 31,2004, we awarded 3,000 restricted common units to each of our six independentdirectors, for a total of 18,000 units with an intrinsic value of $434,000. Eachrestricted unit grant vests in equal one-third annual installments commencingon the first anniversary of the grant date or upon a change of control, death,disability or, in certain circumstances, retirement and the intrinsic value ofthe units is amortized into general and administrative expense over the vestingperiod. On December 13, 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

2005,6,000 of these restricted common units vested. We recognized expense of $13,000related to the amortization of these restricted units in 2004.

*Common Units andJunior Units Prior to the Offering*

In transactions occurringon August 14, 2001 and November 27, 2001, we issued 1,299,020 (asrestated for the conversion related to the Offering) common units and 620,000junior units to Copano Partners in exchange for general and limited partnershipinterests in certain of our operating entities. Prior to the completion of theOffering, a common unitholder could not receive any distributions until thepreferred unitholders had been redeemed in full, other than distributions forany fiscal year, in amounts equal to net taxable income of such unitholder asreflected on its Schedule K-1 multiplied by the maximum federalincome tax rate then in effect. Junior unitholders were entitled to share indistributions only after preferred units had been redeemed in full and aftercommon unitholders had received a distribution of $20 per common unit.

*Common SpecialUnits and Junior Special Units Prior to the Offering*

Effective January 2002, 212,000 of our nonvotingspecial units were designated, 154,000 of which were designated as commonspecial units and 58,000 of which were designated as junior special units. Ofthe designated amounts, 54,000 common special units and 18,000 junior specialunits were sold, effective January 2002, to an executive officer and,effective April 1, 2003, an additional 100,000 common special units and40,000 junior special units were sold to another executive officer. Theacquisition price for the common special units and the junior special units was$1.00 per unit and $0.50 per unit, respectively. The initial purchase of the72,000 special units issued effective January 2002 to an executive officerwas financed by a subscription receivable. The second purchase of the 140,000special units issued effective April 1, 2003 to another executive officerwas financed by a subscription receivable, one third, or $40,000, of which wasforgiven on April 1, 2004.

On July 30, 2004, Copano/Operations, Inc. (“CopanoOperations”), an entity controlled by Mr. Eckel and which provides us withmanagement, operations and administrative support services, loaned these twoexecutive officers a total of $143,000. These officers used the loan proceedsto pay us for the balance of the acquisition price for the special units(subscription receivable). See *Distributions*below.

With respect todistributions, common special unitholders and junior special unitholders hadthe same rights as common unitholders and junior unitholders, respectively;provided, however, that upon certain liquidating events, (i) specialunitholders had a liquidation preference over all other unitholders withrespect to an amount of liquidation proceeds equal to the original acquisitionprice of the special units and (ii) the amount of the balance thatotherwise would be distributed to common special unitholders would be reducedby an amount equal to the number of common special units multiplied by $16.

*Distributions*

Our holders of the common and subordinated units areentitled to participate in distributions. The common units have the right toreceive a minimum quarterly distribution, or MQD, of $0.40 per unit, plus anyarrearages on the common units, before any distribution is made to the holdersof the subordinated units. Subordinated units do not accrue distributionarrearages. After the expiration of the subordination period as defined in ourlimited liability company agreement, common units will no longer be entitled toarrearages.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

On January 18, 2005, our Board of Directorsdeclared an adjusted cash distribution for the partial quarterly period fromthe closing of the Offering on November 15, 2004 through December 31,2004 of $0.20 per unit for all of our outstanding common and subordinated units.The distribution totaling $2,115,000 was paid on February 14, 2005 toholders of record at the close of business on February 1, 2005.

On April 15, 2005 and pursuant to the provisionsof our limited liability company agreement, our Board of Directors declared andwe paid a cash distribution of $533,000 to certain Pre-Offering Investors forreimbursement of their respective tax obligations attributable to theirownership interest in us for the period from January 1, 2004 through November 14,2004, the day prior to the closing of the Offering.

On April 18, 2005, our Board of Directorsdeclared a cash distribution for the three months ended March 31, 2005 of$0.42 per unit for all of our outstanding common and subordinated units. Thedistribution totaling $4,450,000 was paid on May 13, 2005 to holders ofrecord at the close of business on May 2, 2005.

On July 15, 2005, our Board of Directors declareda cash distribution for the three months ended June 30, 2005 of $0.45 perunit for all of our outstanding common and subordinated units. The distributiontotaling $7,819,000 was paid on August 15, 2005 to holders of record atthe close of business on August 1, 2005 and included 1,372,458 commonunits issued in connection with the closing of the ScissorTail Acquisition (seeNotes 4 and 9). This distribution amount also included a concurrentquarterly distribution of $0.495 per unit with respect to 4,830,758 Class Bunits issued in connection with the closing of the ScissorTail Acquisition.

On October 17, 2005, our Board of Directorsdeclared a cash distribution for the three months ended September 30, 2005of $0.50 per unit for all outstanding common and subordinated units. Thedistribution totaling $8,449,000 was paid on November 14, 2005 to holdersof record at the close of business on November 1, 2005.

On January 18, 2006, our Board of Directorsdeclared a cash distribution for the three months ended December 31, 2005of $0.55 per unit for all of our outstanding common and subordinated units. Thedistribution totaling $10,081,000 was paid on February 14, 2006 to holdersof record at the close of business on February 1, 2006.

On July 30, 2004, we made a distribution totaling$143,000 to two executive officers, which they used to retire the obligationsoutstanding under their loans with Copano Operations (discussed above).

On November 15, 2004,after the exchange of existing warrants, common units, common special units,junior units and junior special units for new common units and subordinatedunits and prior to the completion of the Offering to the public, we made aspecial distribution to pre-Offering unitholders totaling $4,000,000, which thepre-Offering unitholders placed in escrow accounts. These escrowed funds were availableto fund general and administrative expenses in excess of limits and for periodsestablished in our limited liability company agreement.

*Unit Options*

Our long-term incentive plan, adopted in November 2004,provides for the grant of restricted units, phantom units, unit options and/orunit appreciation rights to our directors, employees and consultants and toemployees of our affiliates who perform services for us. For purposes of theplan, our affiliates include Copano Operations. The total number of commonunits authorized to be issued under the plan is limited to the lesser of (a) 2,500,000units or (b) the number of units equal to 10% of the sum of total 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

common units outstandingand the total number of common units that may be issued to the holders of anyoutstanding equity securities convertible into common units, exclusive ofoutstanding awards under the plan, determined at the time of any award,provided no more than 30% of the total number of common units authorized to beissued under the plan may be delivered in payment of restricted units and/orphantom units. The plan is administered under the direction of the CompensationCommittee of our Board of Directors.

Unit options are granted under our long-term incentiveplan and have an exercise price that may not be less than the fair market valueof the underlying units on the date of grant. In general, unit options grantedwill become exercisable over a period determined by our Compensation Committee.In addition, unit options will become exercisable upon a change in control,unless provided otherwise by the Compensation Committee.

During the year ended December 31, 2005, wegranted 309,110 unit options to purchase an equal number of common units at anaverage exercise price of $36.51 per unit to our officers and certainemployees, including 169,002 options awarded at the time of the ScissorTailAcquisition to ScissorTail employees. These unit options will vest in fiveequal annual installments commencing with the first anniversary of the grantdate or will become exercisable upon a change of control, death or disability. Theseoutstanding options have remaining contractual lives of approximately10 years at December 31, 2005.

On November 15, 2004, we granted all of ouremployees, excluding Mr. Eckel, a total of 200,000 unit options topurchase an equal number of common units at $20.00 per unit. These unit optionswill vest in five equal annual installments commencing with the firstanniversary of the grant date or will become exercisable upon a change ofcontrol, death or disability. Outstanding options have remaining contractuallives of approximately 9 years at December 31, 2005.

Asummary of the unit option activity is provided below:

| ** **                                     | ** ** | **2004**                                       | ** ** | **2005**                               | ** ** |
|------------------------------------------------|------------|------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                     | ** ** | **Number of  Units  Underlying  Options** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Number of  Units  Underlying  Options** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| Outstanding at  beginning of period            |       |                                           | —     |                                   |       |   | — |   |   |   | 200,000 |   |   |   | $ | 20.00 |   |   |
| Granted                                        |       |                                           | 200,000    |                                   |       |   | $ | 20.00 |   |   |   | 309,110 |   |   |   | 36.51 |   |   |
| Exercised                                      |       |                                           | —     |                                   |       |   | — |   |   |   | (4,440 | ) |   |   | 20.00 |   |   |
| Forfeited                                      |       |                                           | —     |                                   |       |   | — |   |   |   | (13,560 | ) |   |   | 27.75 |   |   |
| Outstanding at  end of period                  |       |                                           | 200,000    |                                   |       |   | $ | 20.00 |   |   |   | 491,110 |   |   |   | $ | 30.18 |   |   |
| Options  exercisable at end of period          |       |                                           | —     |                                   |       |   | — |   |   |   | 37,688 |   |   |   | $ | 20.40 |   |   |
| Weighted average fair  value of option granted |       |                                           |       |                                   |       |   | $ | 1.44 |   |   |   |   |   |   |   | $ | 5.14 |   |   |

 

Exercise prices for unit options outstanding as of December 31,2005 ranged from $20.00 to $40.50.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

**Note 10—RelatedParty Transactions**

*Operations Services*

Through December 31, 2004, we did not directlyemploy any persons to manage or operate our business other than certainDelaware-based officers. With respect to our Texas operating subsidiaries,Copano Operations provided management, operations and administrative supportservices for us. We reimbursed Copano Operations for all direct and indirectcosts of these services. Copano Operations charged these subsidiaries, withoutmarkup, based upon total monthly expenses incurred by Copano Operations less (i) afixed allocation to reflect expenses incurred by Copano Operations for thebenefit of certain entities controlled by Mr. Eckel and (ii) anycosts to be charged directly to an entity for which Copano Operations performedservices. Our management believes that this methodology was reasonable. EffectiveJanuary 1, 2005 and pursuant to a general and administrative servicesagreement with Copano Operations, Copano Operations transferred responsibilityto CPNO Services, L.P., our indirect wholly-owned subsidiary, for a significantportion of the services, including its employment of certain employees on ourbehalf, that Copano Operations had previously provided to us. Under the generaland administrative services agreement, we continue to reimburse CopanoOperations for all direct and indirect costs of the services provided to us byCopano Operations using the same methodology as utilized prior to January 1,2005. For the years ended December 31, 2005, 2004 and 2003, we reimbursedCopano Operations $2,987,000, $15,355,000 and $12,190,000, respectively, foradministrative and operating costs, including payroll and benefits expense forboth our field and administrative personnel. These costs are included inoperations and maintenance expenses and general and administrative expenses onthe consolidated statements of operations. As of December 31, 2005 and2004, amounts due by us to/(from) Copano Operations were $(13,000) and $38,000,respectively.

Our management estimates that these expenses on astand-alone basis (that is, the cost that would have been incurred by usto conduct our current operations if we had obtained these services from anunaffiliated entity) would not be significantly different from the amounts werecorded in our consolidated financial statements for each of the three yearsin the period ended December 31, 2005.

*Natural Gas Transactions*

During the years ended December 31, 2005, 2004and 2003, we purchased natural gas from affiliated companies of Mr. Eckeltotaling $1,495,000, $1,474,000 and $1,896,000, respectively, and providedgathering and compression services to affiliated entities of Mr. Eckeltotaling $31,000, $75,000 and $33,000, respectively. Additionally, affiliatedcompanies of Mr. Eckel reimbursed us $93,000, $53,000 and $34,000 for theyears ended December 31, 2005, 2004 and 2003, respectively, in gas liftcosts which are reflected as a reduction of operations and maintenance expensein the consolidated statements of operations. Our management believes thesepurchases and sales were on terms no less favorable than those that could havebeen achieved with an unaffiliated entity. As of December 31, 2005 and2004, amounts payable by us to affiliated companies of Mr. Eckel, otherthan Copano Operations, totaled $127,000 and $89,000, respectively.

We paid Webb Duval fortransportation and purchased natural gas from Webb Duval. Natural gas purchasesand transportation, net of natural gas sales to Webb Duval, totaled $3,479,000,$926,000 and $665,000, for the years ended December 31, 2005, 2004 and2003, respectively. Well connection fees paid to Webb Duval totaled $67,000 forthe year ended December 31, 2005. Additionally, as operator of WebbDuval, we charge Webb Duval a monthly administrative fee of $16,000 and havemade advances to Webb 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

Duvalfor capital expenditures. As of December 31, 2005 and 2004, our netreceivable from Webb Duval totaled $75,000 and $1,141,000, respectively.

**Note 11—Customer Information**

We had three third-party customers thataccounted for 26% (Texas Gulf Coast Pipelines and Processing), 14%(Mid-Continent Operations) and 12% (Texas Gulf Coast Processing) of ourconsolidated revenue in 2005. We had three third-party customers thataccounted for 27% (Texas Gulf Coast Pipelines and Processing), 22% (Texas GulfCoast Processing) and 14% (Texas Gulf Coast Processing) of our consolidatedrevenue in 2004. We had four third-party customers that accounted for 33%(Texas Gulf Coast Pipelines and Processing), 14% (Texas Gulf Coast Pipelines),9% (Texas Gulf Coast Pipelines and Processing) and 8% (Texas Gulf CoastPipelines) of our consolidated revenue in 2003. See Note 16 for additionalsegment information.

We had two major suppliers in 2005 that accounted for8% (Mid-Continent Operations) and 7% (Texas Gulf Coast Pipelines) of ourconsolidated cost of natural gas sold. We had two major suppliers in 2004 thataccounted for 11% and 8% of our consolidated cost of natural gas sold. We hadtwo major suppliers in 2003 that accounted for 8% and 8% of our consolidatedcost of natural gas sold. All of these major suppliers during the years ended December 31,2004 and 2003 sold volumes to the Texas Gulf Coast Pipelines segment. SeeNote 16 for additional segment information.

We had three third-partycustomers that accounted for 27% (Mid-Continent Operations), 23% (Texas GulfCoast Pipelines and Processing) and 10% (Texas Gulf Coast Pipelines) of ourconsolidated accounts receivable as of December 31, 2005. We had threethird-party customers that accounted for 31% (Texas Gulf Coast Pipelinesand Processing), 29% (Texas Gulf Coast Processing) and 11% (Texas Gulf CoastPipelines) of our consolidated accounts receivable as of December 31, 2004.We had four third-party customers that accounted for 26% (Texas GulfCoast Pipelines and Processing), 15% (Texas Gulf Coast Pipelines), 13% (TexasGulf Coast Processing) and 12% (Texas Gulf Coast Pipelines) of our consolidatedaccounts receivable as of December 31, 2003. See Note 16 foradditional segment information.

**Note 12—Risk Management Activities**

Weare exposed to market risks, including changes in commodity prices and interestrates. We may use financial instruments such as puts, swaps, options and otherfinancial instruments to mitigate the effects of the identified risks. Ingeneral, we attempt to hedge risks related to the variability of futureearnings and cash flows resulting from changes in applicable commodity pricesor interest rates so that we can maintain cash flows sufficient to meet debt service,required capital expenditures distribution objectives, and similar requirements.Our Risk Management Policy prohibits the use of derivative instruments forspeculative purposes.

*Commodity RiskHedging Program*

Our profitability is affected by prevailing NGL andnatural gas prices. NGL and natural gas prices are volatile and are impacted bychanges in the supply and demand for NGLs and natural gas, as well as marketuncertainty and a variety of additional factors that are beyond our control. Inorder to manage the risks associated with natural gas and NGL prices, we engagein risk management activities that take the form of commodity derivativeinstruments. These activities are governedby our Risk Management Policy, which allows our management to purchase crudeoil and natural gas liquids puts and certain natural gas put 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

orcall options in order to reduce our exposure to a substantial adverse change inthe prices of those commodities. Our Risk Management Committee monitors andensures compliance with the Risk Management Policy and is comprised of seniorlevel executives in the operations, finance and legal departments. The Audit Committeeof our Board of Directors monitors the implementation of the policy and we haveengaged an independent firm to provide additional oversight. The RiskManagement Policy requires derivative transactions to take place either on theNew York Mercantile Exchange (NYMEX) through a clearing member firm or withover the counter counterparties with investment grade ratings from both Moody’sand Standard & Poor’s. Potential derivative transactions are analyzedto evaluate their effectiveness within the risk management strategy.

In late July 2005, we entered into puttransactions for the sale of West Texas Intermediate crude oil with a combinednotional amount of 60,000 barrels per month for a term from September 2005through December 2007. The derivatives are intended to hedge the risk ofweakening NGL prices with offsetting increases in the value of the puts basedon the correlation between NGL prices and crude oil prices. We designated thesetwo transactions as cash flow hedges under SFAS No. 133 effective October 25,2005. For the year ended December 31, 2005, we recorded a fair value gainin other revenue of $405,000 related to these put contracts prior to theirdesignation as cash flow hedges. Subsequent to their designation, we recorded anet loss due to ineffectiveness of $35,000, and a reduction to other revenue of$3,000 resulting from forecasted transactions realized in 2005. We estimatethat $0.7 million of the amount reported in other comprehensive loss as ofDecember 31, 2005 will be reclassified against earnings in the next 12 months.We do not believe that it is probable that any forecasted transactions will notoccur, and therefore do not anticipate any gains or losses from discontinuanceof the hedges in the next 12 months. As of December 31, 2005, the fairvalue of the puts was $2,927,000.

In December 2005, we entered into additionalcommodity hedging transactions to hedge our exposure related to market pricesfor natural gas and NGLs, which as of December 31, 2005, consisted ofnatural gas puts with terms from January 2006 through December 2009,and swaps and NGL puts and swaps with terms from January 2006 through December 2008.These derivatives are intended to hedge the risk of extreme adverse price fluctuationson our production of the commodities hedged. These financial instruments aredesignated as cash flow hedges under SFAS No. 133. The instruments arerecorded on our consolidated balance sheets at fair value. Changes in the fairvalue over time are generally recorded to other comprehensive income. Gains orlosses are recorded to our consolidated statements of operations as forecastedtransactions are realized and for ineffectiveness of the hedging relationship,if any. During 2005, we recorded a loss of $7,000 related to ineffectiveness onthese instruments which is reflected in other revenue in our consolidatedstatements of operations. There was no gain or loss realized in 2005 onrealized forecasted transactions for these derivatives. We estimate that $2.9 millionof the amount reported in other comprehensive loss as of December 31, 2005will be reclassified against earnings in the next 12 months. We do not believethat it is probable that any forecasted transactions will not occur, andtherefore do not anticipate any gains or losses from discontinuance of thehedges in the next 12 months. As of December 31, 2005, the net fair valueof these commodity financial instruments totaled $28,117,000, which iscomprised of an asset of $31,835,000 and a liability of $3,718,000.

For the years ended December 31, 2004, and 2003,no such hedging positions were purchased or exercised and no option positionswere outstanding as of December 31, 2004 or 2003.

Prior to our acquisitionof ScissorTail, it entered into certain derivative transactions on behalf ofthree suppliers from whom ScissorTail purchased a significant volume of naturalgas. The arrangement with the 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

suppliersprovided that any gains or losses that resulted from the derivativetransactions passed through to the suppliers. ScissorTail’s credit exposure wasguaranteed by the physical production from the three suppliers. The potentialcredit risk for each of the suppliers was evaluated on a regular basis and thevolume available to hedge was modified to match a percentage of the supplier’sactual volumes sold to ScissorTail. ScissorTail received a fee of $1,000 permonth related to these transactions. ScissorTail did not and we have notrecorded any other revenue or expenses associated with these derivativetransactions. In October 2005, all of the positions under these derivativetransactions expired.

*Interest Rate RiskHedging Program*

Our interest rate exposure results from variable rateborrowings under our debt agreements. We manage a portion of our interest rateexposure by utilizing interest rate swaps, which allow us to convert a portionof variable rate debt into fixed rate debt.

In October 2005,we entered into two interest rate swap agreements with an aggregate notionalamount of $50 million in which we exchanged the payment of variable rateinterest on a portion of the principal outstanding under the Credit Facilityfor fixed rate interest. We have designated these two interest rate swaps ascash flow hedges under SFAS No. 133. Under each swap agreement, we pay thecounterparties the fixed interest rate of approximately 4.7% monthly andreceive back from the counterparties a variable interest rate based on one-monthLIBOR rates. The interest rate swaps cover the period from October 2005through July 2010 and the settlement amounts will be recognized toearnings as either an increase or a decrease in interest expense.

| ** **             | **Effective Date** | ** ** | ** **          | **Expiration Date** | ** ** | **Notional  Amount** | ** ** | **Fixed  Rate** | ** ** | **Amounts  Paid in  2005** | ** ** | **Fair Value  December 31,  2005** | ** ** |
|------------------------|-------------------------|------------|---------------------|--------------------------|------------|----------------------|------------|-----------------|------------|---------------------------------|------------|----------------------------------------------|------------|
| October 24, 2005  |                    |       | July 31,  2010 |                     |       | $                    | 25,000,000 |            | 4.7150     | %                               | $          | 26,490                                       |       |   | $ | 37,544 |   |   |
| October 24,  2005 |                    |       | July 31, 2010  |                     |       | 25,000,000           |       | 4.7075          | %          | 27,881                          |       |                                         | 45,352     |   |   |
|                        |                         |            |                     |                          |            |                      |            |                 |            |                                 |            |                                              |            |  |  |  |  |  |  |  |

 

TheCHC Credit Agreement and CPG Credit Agreement required us to enter intointerest rate risk management activities. In March 2002, we entered intointerest rate swap agreements with Fleet under the then existing credit facilities.Amounts received or paid under these swaps were recorded as reductions orincreases in interest expense. The table below summarizes the terms and amountspaid in 2003 of the various interest swaps:

| ** **          | **Effective Date** | ** **              | ** ** | **Expiration Date** | ** ** | **Notional  Amount** | ** ** | **Fixed  Rate** | ** ** | **Amounts  Paid in  2003** | ** ** |
|---------------------|-------------------------|-------------------------|------------|--------------------------|------------|----------------------|------------|-----------------|------------|---------------------------------|------------|
| March 1, 2002  |                    | March 1,  2003     |       | $                        | 15,000,000 |                 |       | 2.57            | %          |                            | $          | 43,391 |   |
| March 1, 2002  |                    | September 1,  2003 |       | 5,000,000                |       |                 | 3.03       | %               |       | 64,014                          |       |
| March 1,  2002 |                    | September 1,2003   |       | 10,000,000               |       |                 | 3.03       | %               |       | 128,028                         |       |
|                     |                         |                         |            |                          |            |                      |            |                 |            |                                 |            |  |  |  |  |

 

**Note 13—FairValue of Financial Instruments**

The carrying amount ofcash equivalents is believed to approximate their fair values because of theshort maturities of these instruments. As of December 31, 2005 and 2004,the debt associated with the Credit Facility, Term Loan Facility, CPG CreditAgreement (repaid in August 2005) and the CHC Facility (repaid in August 2005)bore interest at floating rates. As such, carrying amounts of these debtinstruments approximate fair values.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

**Note 14—Commitmentsand Contingencies**

*Commitments*

For the years ended December 31, 2005, 2004 and2003, rental expense for office space, leased vehicles and leased compressorsand related field equipment used in our operations totaled $1,642,000,$1,598,000 and $1,631,000, respectively. As of December 31, 2005,commitments under our lease obligations for the next five years and thereafterare payable as follows: *2006—*$1,975,000;*2007—*$800,000; *2008—*$674,000;*2009—*$374,000; and *2010—*$143,000.During 2003, certain of our subsidiaries became co-lessors of office space withCopano Operations.

We have both fixed andvariable quantity contractual commitments arising in the ordinary course of ournatural gas marketing activities. As of December 31, 2005, we had fixedcontractual commitments to purchase 169,725 million British thermal units(“MMBtu”) of natural gas in January 2006. As of December 31, 2005, wehad fixed contractual commitments to sell 3,354,200 MMBtu of natural gasin January 2006. All of these contracts are based on index-relatedmarket pricing. Using index-related market prices as of December 31,2005, total commitments to purchase natural gas related to such agreementsequaled $1,316,000 and the total commitment to sell natural gas under suchagreements equaled $28,880,000. Our commitments to purchase variable quantitiesof natural gas at index-based prices range from contract periodsextending from one month to the life of the dedicated production. During December 2005,natural gas volumes purchased under such contracts equaled 8,028,881 MMBtu.Our commitments to sell variable quantities of natural gas at index-basedprices range from contract periods extending from one month to 2012. During December 2005,natural gas volumes sold under such contracts equaled 3,694,465 MMBtu.

*Guarantees*

In November 2002, the FASB issued FIN 45, *“Guarantor’s Accounting and Disclosure Requirements for Guarantees,Including Indirect Guarantees of Indebtedness of Others.”*  In certain instances, this interpretationrequires a guarantor to recognize, at the inception of a guarantee, a liabilityfor the fair value of the obligation undertaken in issuing the guarantee.

Certainof the Texas Gulf Coast Pipelines entities currently guarantee vehicle leasepayment obligations, including the residual sales value under the vehicleleases. As of December 31, 2005, we guaranteed $178,000 related to leasepayment obligations. As of December 31, 2005, aggregate guaranteedresidual values for vehicles under these operating leases were as follows (inthousands):

| ** **             | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Lease residual  values |       |     | $          | 36       |       |     |       | $        | 55         |           |       |      | $          | 54 |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 145 |   |
|                        |            |          |            |          |            |          |            |          |            |                |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Effective April 12, 2003, we have guaranteedcertain telephone equipment lease obligations (approximately $15,000 of leasepayment obligations as of December 31, 2005) of Copano Operations. Priorto January 1, 2005, our use of this telephone equipment was included inthe support services provided by Copano Operations to us. See Note 10.

Presently, we do not have any other types ofguarantees outstanding that require liability recognition under the provisionsof FIN 45.

F-41

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

FIN 45also sets forth disclosure requirements for guarantees by a parent company onbehalf of its subsidiaries. We may, from time to time, issue parent guaranteesof commitments resulting from the ongoing activities of subsidiary entities. Additionally,a subsidiary entity may from time to time issue a guarantee of commitmentsresulting from the ongoing activities of another subsidiary entity. Theguarantees generally arise in connection with a subsidiary commodity purchaseobligation, subsidiary lease commitments and subsidiary bank debt. The natureof such guarantees is to guarantee the performance of the subsidiary entitiesin meeting their respective underlying obligations. Except for operating leasecommitments, all such underlying obligations are recorded on the books of thesubsidiary entities and are included in our consolidated financial statementsas obligations of the combined entities. Accordingly, such obligations are notrecorded again on the books of the parent. The parent would only be called uponto perform under the guarantee in the event of a payment default by theapplicable subsidiary entity. In satisfying such obligations, the parent wouldfirst look to the assets of the defaulting subsidiary entity. As of December 31,2005, the approximate amount of parental guaranteed obligations were as follows(in thousands):

| ** **           | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|----------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Bank debt            |       | $        | —     |     |       | $        | —     |     |       |     | $          | —         |       |      |       | $ | — |   |   | $ | 228,000 |   | $ | 170,000 |   | $ | 398,000 |   |
| Commodity  purchases |       | 1,100    |       |     | —     |     |       |     | —     |     |       |           | —     |      |       | — |   | — |   | 1,100 |   |
|                 |       | $        | 1,100      |     |       | $        | —     |     |       |     | $          | —         |       |      |       | $ | — |   |   | $ | 228,000 |   | $ | 170,000 |   | $ | 399,100 |   |

 

*RegulatoryCompliance*

In the ordinary course ofbusiness, we are subject to various laws and regulations. In the opinion of ourmanagement, compliance with existing laws and regulations will not materiallyaffect our financial position.

*Litigation*

Although we may, from timeto time, be involved in litigation and claims arising out of our operations inthe normal course of business, we are not currently a party to any materiallegal proceedings. In addition, we are not aware of any material legal orgovernmental proceedings against us, or contemplated to be brought against us,under the various environmental protection statutes to which we are subject,that would have a significant adverse effect on our financial position orresults of operations.

**Note 15—SupplementalDisclosures to the Statements of Cash Flows**

*Cash paid during each of the periods presented (inthousands)*

| ** ** | ** ** | **Year Ended December 31,** | ** ** |
|------------|------------|--------------------------------------------|------------|
| ** ** | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Interest   |       | $                                          | 9,666      |   | $ | 3,891 |   | $ | 1,611 |   |
| Taxes      |       | $                                          | 15         |   | $ | — |   | $ | 28 |   |

 

F-42

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  (Continued)**

*Supplemental disclosures of noncash investing andfinancing activities (in thousands)*

| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Decrease  (increase) in equity in earnings (loss) from unconsolidated affiliates  |       | $                                          | 120        |   | $ | 120 |   | $ | 120 |   |
| Decrease in  accounts receivable from affiliates                                  |       | (120                                       | )          | (120 | ) | (120 | ) |
| (Decrease)  increase other comprehensive income (loss)                            |       | —                                     |       | — |   | 226 |   |
| Increase  (decrease) other current liabilities                                    |       | 1,015                                      |       | — |   | (226 | ) |
| Increase in  property, plant and equipment                                        |       | (3,448                                     | )          | (890 | ) | — |   |
| Increase in other  noncurrent liabilities                                         |       | 215                                        |       | 890 |   | — |   |
| Issuance of  subordinated notes                                                   |       | —                                     |       | — |   | 850 |   |
| Decrease in other  current liabilities                                            |       | —                                     |       | — |   | (850 | ) |
| Increase in offering costs                                                        |       | (561                                       | )          | — |   | — |   |
| Increase in other assets                                                          |       | (24                                        | )          | — |   | — |   |
| Increase in accounts payable                                                      |       | 2,899                                      |       | — |   | — |   |
| Increase in notes  payable                                                        |       | 2,129                                      |       | — |   | — |   |
| Increase in  prepayments and other current assets                                 |       | (2,129                                     | )          | — |   | — |   |
| Increase of  redeemable preferred units related to the issuance of PIK units      |       | —                                     |       | — |   | 2,453 |   |
| Decrease in  members’ capital related to the issuance of PIK units           |       | —                                     |       | — |   | (2,453 | ) |
| Increase of  redeemable preferred units related to the accretion of warrant value |       | —                                     |       | — |   | 743 |   |
| Decrease in  members’ capital related to the accretion of warrant value      |       | —                                     |       | — |   | (743 | ) |
| Increase in  members’ capital                                                |       | —                                     |       | — |   | 1,258 |   |
| Decrease of redeemable  preferred units                                           |       | —                                     |       | — |   | (1,258 | ) |
|                                                                                   |            |                                            |            |  |  |  |  |  |  |  |

 

**Note 16—Segment Information**

We manage our business and analyze and report ourresults of operations on a segment basis. Prior to the ScissorTail Acquisition,we divided our operations into two business segments: (i) CopanoPipelines, which performs natural gas gathering and transmission and relatedoperations in Texas and (ii) Copano Processing, which performs our naturalgas processing, treating, conditioning and related NGL transportationoperations in Texas. Following the ScissorTail Acquisition, our operations aredivided into the following four business segments for both internal andexternal reporting and analysis:  (i) TexasGulf Coast Pipelines, formerly Copano Pipelines, (ii) Texas Gulf CoastProcessing, formerly Copano Processing, (iii) Mid-Continent Operations,which includes natural gas midstream services in central and eastern Oklahoma,including natural gas gathering and related compression and dehydrationservices and natural gas processing and (iv) Corporate, which engages inrisk management and other corporate activities. We evaluate segment performancebased on segment gross margin before depreciation and amortization. All of ourrevenue is derived from, and all of our assets and operations are located in,the Texas Gulf Coast region and central and eastern Oklahoma of the UnitedStates. Transactions between reportable segments are conducted on an arm’slength basis.

 

F-43

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

Summarizedfinancial information concerning our reportable segments is shown in thefollowing table (in thousands): 

| ** **                                           | ** ** | **Texas Gulf  Coast  Pipelines** | ** ** | **Texas Gulf  Coast  Processing** | ** ** | **Mid-  Continent  Operations** | ** ** | **Corporate** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|------------------------------------------------------|------------|---------------------------------------|------------|----------------------------------------|------------|---------------------------------|------------|---------------|------------|------------------|------------|-----------|------------|
| ***Year  Ended December 31, 2005:***            |       |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |
| Sales to external customers                          |       | $                                     | 373,007    |                                   | $          | 173,950                         |       |          | $          | 200,426          |       |      | $          | 360 |   |   | $ | — |   |   | $ | 747,743 |   |
| Intersegment sales                                   |       | 202,414                               |       | 65,411                                 |       |                            | —     |          |       | —           |       |      | (267,825   | ) |   | — |   |
| Interest and other financing costs                   |       | 3,468                                 |       | 456                                    |       |                            | —     |          |       | 16,923           |       |      | (386       | ) |   | 20,461 |   |
| Depreciation and amortization                        |       | 5,296                                 |       | 2,435                                  |       |                            | 9,181      |          |       | 140              |       |      | —     |   |   | 17,052 |   |
| Equity in (earnings) loss in consolidated affiliates |       | (934                                  | )          | —                                 |       |                            | 7          |          |       | —           |       |      | —     |   |   | (927 | ) |
| Segment profit (loss)                                |       | 11,553                                |       | 17,163                                 |       |                            | 23,610     |          |       | (21,974          | )          |      | —     |   |   | 30,352 |   |
| Segment assets                                       |       | 146,217                               |       | 74,495                                 |       |                            | 573,795    |          |       | 45,808           |       |      | (47,565    | ) |   | 792,750 |   |
| Capital expenditures                                 |       | 5,544                                 |       | 2,094                                  |       |                            | 484,206    |          |       | 1,128            |       |      | —     |   |   | 492,972 |   |
| ***Year Ended December 31,  2004:***            |       |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |
| Sales to external customers                          |       | $                                     | 274,595    |                                   | $          | 163,061                         |       |          | $          | —           |       |      | $          | — |   |   | $ | — |   |   | $ | 437,656 |   |
| Intersegment sales                                   |       | 146,812                               |       | 18,442                                 |       |                            | —     |          |       | —           |       |      | (165,254   | ) |   | — |   |
| Interest and other financing costs                   |       | 2,971                                 |       | 3,134                                  |       |                            | —     |          |       | 17,643           |       |      | (588       | ) |   | 23,160 |   |
| Depreciation and amortization                        |       | 4,832                                 |       | 2,390                                  |       |                            | —     |          |       | 65               |       |      | —     |   |   | 7,287 |   |
| Equity in earnings in consolidated affiliate         |       | (419                                  | )          | —                                 |       |                            | —     |          |       | —           |       |      | —     |   |   | (419 | ) |
| Segment profit (loss)                                |       | 11,878                                |       | 7,195                                  |       |                            | —     |          |       | (19,988          | )          |      | —     |   |   | (915 | ) |
| Segment assets                                       |       | 150,375                               |       | 68,966                                 |       |                            | —     |          |       | 1,383            |       |      | (42,325    | ) |   | 178,399 |   |
| Capital expenditures                                 |       | 7,989                                 |       | 820                                    |       |                            | —     |          |       | 111              |       |      | —     |   |   | 8,920 |   |
| ***Year Ended December 31,  2003:***            |       |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |
| Sales to external customers                          |       | $                                     | 265,121    |                                   | $          | 119,450                         |       |          | $          | —           |       |      | $          | — |   |   | $ | — |   |   | $ | 384,571 |   |
| Intersegment sales                                   |       | 139,824                               |       | 42,116                                 |       |                            | —     |          |       | —           |       |      | (181,940   | ) |   | — |   |
| Interest and other financing costs                   |       | 2,837                                 |       | 3,740                                  |       |                            | —     |          |       | 5,531            |       |      | —     |   |   | 12,108 |   |
| Depreciation and amortization                        |       | 4,328                                 |       | 1,755                                  |       |                            | —     |          |       | 8                |       |      | —     |   |   | 6,091 |   |
| Equity in loss from unconsolidated affiliate         |       | 127                                   |       | —                                 |       |                            | —     |          |       | —           |       |      | —     |   |   | 127 |   |
| Segment profit (loss)                                |       | 10,567                                |       | (9,375                                 | )          |                            | —     |          |       | (5,909           | )          |      | —     |   |   | (4,717 | ) |
| Capital  expenditures                                |       | 3,727                                 |       | 2,465                                  |       |                            | —     |          |       | —           |       |      | —     |   |   | 6,192 |   |

 

F-44

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 17—QuarterlyFinancial Data (Unaudited)**

| ** **                   | ** ** | **Year 2005**      | ** ** |
|------------------------------|------------|-------------------------|------------|
| ** **                   | ** ** | **Quarter Ended**  | ** ** | ** ** | ** ** |
| ** **                   | ** ** | **March 31**       | ** ** | **June 30** | ** ** | **September 30(1)** | ** ** | **December 31(1)** | ** ** | **Year** | ** ** |
| ** **                   | ** ** | **(in thousands)** | ** ** |
| Revenue                      |       | $                       | 126,850    |   | $ | 109,122 |   |   | $ | 216,667 |   |   |   | $ | 295,104 |   |   | $ | 747,743 |   |
| Operating income             |       | 6,381                   |       | 6,399 |   |   | 13,533 |   |   |   | 23,860 |   |   | 50,173 |   |
| Net income                   |       | 5,425                   |       | 5,516 |   |   | 5,159 |   |   |   | 14,252 |   |   | 30,352 |   |
| Basic net income  per unit   |       | 0.51                    |       | 0.52 |   |   | 0.35 |   |   |   | 0.85 |   |   | 2.31 |   |
| Diluted net income per  unit |       | 0.51                    |       | 0.52 |   |   | 0.35 |   |   |   | 0.84 |   |   | 2.29 |   |
|                              |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

| ** **                          | ** ** | **Year 2004**      | ** ** |
|-------------------------------------|------------|-------------------------|------------|
| ** **                          | ** ** | **Quarter Ended**  | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **March 31**       | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** | **Year** | ** ** |
| ** **                          | ** ** | **(in thousands)** | ** ** |
| Revenue                             |       | $                       | 96,146     |   | $ | 100,373 |   |   | $ | 120,796 |   |   |   | $ | 120,341 |   |   | $ | 437,656 |   |
| Operating income                    |       | 3,492                   |       | 3,008 |   |   | 6,483 |   |   |   | 9,177 |   |   | 22,160 |   |
| Net (loss) income                   |       | (620                    | )          | (592 | ) |   | 2,703 |   |   |   | (2,406 | ) |   | (915 | ) |
| Basic net (loss)  income per unit   |       | (0.43                   | )          | (0.42 | ) |   | 1.90 |   |   |   | (0.39 | ) |   | (0.35 | ) |
| Diluted net  (loss) income per unit |       | (0.43                   | )          | (0.42 | ) |   | 0.98 |   |   |   | (0.39 | ) |   | (0.35 | ) |
|                                     |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

----

(1)          Our historical resultsof operations for the quarters ended September 30, 2005 and December 31,2005 may not be comparable to earlier 2005 quarters or to the comparative prioryear quarters as a result of the ScissorTail Acquisition on August 1,2005.

F-45

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

Tothe Operating General Partner of Webb/Duval Gatherers:

Houston, Texas

We have audited the accompanying balance sheet ofWebb/Duval Gatherers (the “Partnership”) as of December 31, 2004, and therelated statements of operations, partners’ capital and cash flows for the yearended December 31, 2004. These financial statements are the responsibilityof the Partnership’s management. Our responsibility is to express an opinion onthese financial statements based on our audits.

We conducted our audit in accordance with standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement. ThePartnership is not required to have, nor were we engaged to perform, an auditof its internal control over financial reporting. Our audit includedconsideration of internal control over financial reporting as a basis fordesigning audit procedures that are appropriate in the circumstances, but notfor the purpose of expressing an opinion on the effectiveness of the Company’sinternal control over financial reporting. Accordingly, we express no suchopinion. An audit includes examining, on a test basis, evidence supporting theamounts and disclosures in the financial statements, assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that ouraudit provides a reasonable basis for our opinion.

In our opinion, suchfinancial statements present fairly, in all material respects, the financialposition of the Partnership at December 31, 2004, and the results of itsoperations and its cash flows for the year ended December 31, 2004 inconformity with accounting principles generally accepted in the United Statesof America.
| /s/ DELOITTE &  TOUCHE LLP |
|-------------------------------------|
| Houston, Texas                      |
| March 29, 2005                 |

 

F-46

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**WEBB/DUVAL GATHERERS**

**BALANCE SHEETS**

| ** **                                    | ** ** | **December 31,** | ** ** |
|-----------------------------------------------|------------|-----------------------|------------|
| ** **                                    | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                    | ** ** | **(unaudited)**       | ** ** | ** ** | ** ** |
| **Assets**                                    |       |                  |       |   |   |
| Current assets:                               |       |                  |       |   |   |
| Cash and cash equivalents                     |       | $                     | 961,297    |   | $ | 114,495 |   |
| Accounts receivable                           |       | 1,650,258             |       | 2,174,378 |   |
| Accounts receivable from affiliates           |       | 748,847               |       | 42,162 |   |
| Prepayments and other current assets          |       | 17,600                |       | 17,194 |   |
| Total current assets                          |       | 3,378,002             |       | 2,348,229 |   |
| Property and equipment, net                   |       | 8,031,894             |       | 8,283,335 |   |
| Total assets                                  |       | $                     | 11,409,896 |   | $ | 10,631,564 |   |
| **Liabilities  and Partners’ Capital**   |       |                  |       |   |   |
| Current liabilities:                          |       |                  |       |   |   |
| Accounts payable                              |       | $                     | 1,704,462  |   | $ | 1,340,194 |   |
| Accounts payable to affiliates                |       | 996,303               |       | 1,897,250 |   |
| Total current liabilities                     |       | 2,700,765             |       | 3,237,444 |   |
| Noncurrent liabilities                        |       | 44,386                |       | — |   |
| Commitments and  contingencies (Note 9)  |       |                  |       |   |   |
| Total partners’  capital                 |       | 8,664,745             |       | 7,394,120 |   |
| Total liabilities  and partners’ capital |       | $                     | 11,409,896 |   | $ | 10,631,564 |   |

 

The accompanying notes are an integral part of these financial statements.

F-47

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**WEBB/DUVALGATHERERSSTATEMENTS OF OPERATIONS**

| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                        | ** ** | **(unaudited)**                            | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| Revenue:                                          |       |                                       |       |   |   |   |   |
| Natural gas sales                                 |       | $                                          | 105,851    |   | $ | 330,919 |   | $ | 475,428 |   |
| Natural gas sales to affiliates                   |       | 3,953,330                                  |       | 2,144,428 |   | 954,165 |   |
| Transportation and gathering fees                 |       | 1,014,645                                  |       | 1,018,399 |   | 1,040,478 |   |
| Transportation and gathering fees from affiliates |       | 628,775                                    |       | 640,812 |   | 285,498 |   |
| Condensate sales                                  |       | 1,033,180                                  |       | 421,169 |   | 424,279 |   |
| Other                                             |       | 6,400                                      |       | 26,264 |   | — |   |
| Other—affiliates                             |       | 67,033                                     |       | 23,000 |   | — |   |
| Total revenue                                     |       | 6,809,214                                  |       | 4,604,991 |   | 3,179,848 |   |
| Costs and  expenses:                              |       |                                       |       |   |   |   |   |
| Cost of natural gas sold                          |       | 2,963,843                                  |       | 575,735 |   | 960,607 |   |
| Cost of natural gas—affiliates               |       | 544,074                                    |       | 1,642,916 |   | 907,799 |   |
| Operations and maintenance                        |       | 924,723                                    |       | 853,057 |   | 711,537 |   |
| Depreciation and amortization                     |       | 701,552                                    |       | 654,929 |   | 591,215 |   |
| General and administrative                        |       | 284,227                                    |       | 315,536 |   | 275,494 |   |
| Taxes other than income                           |       | 120,170                                    |       | 116,518 |   | 160,942 |   |
| Total cost and expenses                           |       | 5,538,589                                  |       | 4,158,691 |   | 3,607,594 |   |
| Net income (loss)                                 |       | $                                          | 1,270,625  |   | $ | 446,300 |   | $ | (427,746 | ) |

 

The accompanying notes are an integral part of these financial statements.

F-48

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**WEBB/DUVALGATHERERSSTATEMENTS OF CASH FLOWS**

| ** **                                                                                | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                | ** ** | **(unaudited)**                            | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| Cash Flows From  Operating Activities:                                                    |       |                                       |       |   |   |   |   |
| Net income (loss)                                                                         |       | $                                          | 1,270,625  |   | $ | 446,300 |   | $ | (427,746 | ) |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities: |       |                                       |       |   |   |   |   |
| Depreciation and amortization                                                             |       | 701,552                                    |       | 654,929 |   | 591,215 |   |
| Other noncash items                                                                       |       | 10,544                                     |       | — |   | — |   |
| (Increase)  decrease in:                                                                  |       |                                       |       |   |   |   |   |
| Accounts receivable                                                                       |       | 524,120                                    |       | 476,781 |   | (1,118,049 | ) |
| Accounts receivable from affiliates                                                       |       | (706,685                                   | )          | 41,704 |   | 194,212 |   |
| Prepayments and other current assets                                                      |       | (406                                       | )          | 1,619 |   | (107 | ) |
| Increase  (decrease) in:                                                                  |       |                                       |       |   |   |   |   |
| Accounts payable                                                                          |       | 364,268                                    |       | (1,692,547 | ) | 643,979 |   |
| Accounts payable to affiliates                                                            |       | (900,947                                   | )          | 312,342 |   | 868,308 |   |
| Other current liabilities                                                                 |       | —                                     |       | (35,380 | ) | 33,048 |   |
| Net cash provided by operating activities                                                 |       | 1,263,071                                  |       | 205,748 |   | 784,860 |   |
| Cash Flows From  Investing Activities:                                                    |       |                                       |       |   |   |   |   |
| Additions to property and equipment                                                       |       | (416,269                                   | )          | (412,466 | ) | (542,063 | ) |
| Net cash used in investing activities                                                     |       | (416,269                                   | )          | (412,466 | ) | (542,063 | ) |
| Cash Flows From  Financing Activities:                                                    |       | —                                     |       | — |   | — |   |
| Net increase (decrease) in cash and cash equivalents                                      |       | 846,802                                    |       | (206,718 | ) | 242,797 |   |
| Cash and cash  equivalents, beginning of year                                             |       | 114,495                                    |       | 321,213 |   | 78,416 |   |
| Cash and cash  equivalents, end of year                                                   |       | $                                          | 961,297    |   | $ | 114,495 |   | $ | 321,213 |   |

 

The accompanying notes are an integral part of these financial statements.

F-49

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**WEBB/DUVALGATHERERSSTATEMENTS OF PARTNERS’ CAPITAL**

| Balance,  December 31, 2002             |   | $         | 7,375,566 |   |
|----------------------------------------------|--------|-----------|-----------|--------|
| Net loss  (unaudited)                        |   | (427,746  | )         |
| Balance,  December 31, 2003 (unaudited) |   | 6,947,820 |      |
| Net income                                   |   | 446,300   |      |
| Balance,  December 31, 2004             |   | 7,394,120 |      |
| Net income  (unaudited)                      |   | 1,270,625 |      |
| Balance,  December 31, 2005 (unaudited) |   | $         | 8,664,745 |   |

 

The accompanying notes are an integral part of these financial statements.

F-50

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS**

**Note 1—Organizationand Basis of Presentation**

Webb/Duval Gatherers (the “Partnership”), a Texasgeneral partnership, was formed in December 1987 to provide gathering andtransportation services to producers of natural gas in the South Texas region. ThePartnership owns three pipeline systems, the Webb/Duval Gathering System, theOlmitos Gathering System and the Cinco Compadres Gathering System. In February 2002,Copano/Webb-Duval Pipeline, L.P. (“CWDPL”) (formerly Copano/Webb-DuvalPipeline, Inc.), a wholly-owned indirect subsidiary of Copano Energy,L.L.C. (“CE”), increased its ownership interest in the Partnership from a 15%general partnership interest to a 62.5% general partnership interest. As aresult of CWDPL’s acquisition of this additional 47.5% general partnershipinterest in the Partnership, CWDPL assumed operations of the Partnership fromthe previous operator on February 1, 2002. The remaining partners, thathave substantive participating rights with respect to the management of thePartnership, collectively own a 37.5% general partnership interest in thePartnership.

The accompanying financialstatements include the assets, liabilities and results of operations of thePartnership as of December 31, 2005 and 2004 and for the years ended December 31,2005, 2004 and 2003.

**Note 2—Summaryof Significant Accounting Policies**

*Use of Estimates*

The preparation of thefinancial statements in conformity with accounting policies generally acceptedin the United States of America requires management to make estimates andassumptions that affect the reported amounts of assets, liabilities, revenueand expenses and disclosure of contingent assets and liabilities that exist atthe date of the financial statements. Although, management believes theestimates are appropriate; actual results can differ from those estimates.

*Cash and CashEquivalents*

Cash and cash equivalentsinclude certificates of deposit with maturities of three months or less at thetime of purchase.

*Concentration andCredit Risk*

Financial instruments that potentially subject thePartnership to concentrations of credit risk consist principally of cash andcash equivalents and accounts receivable.

The Partnership places itscash and cash equivalents with high-quality institutions and in money market funds.The Partnership derives its revenue from customers primarily in the natural gasindustry. This industry concentration has the potential to impact thePartnership’s overall exposure to credit risk, either positively or negativelyin that the Partnership’s customers could be affected by similar changes ineconomic, industry or other conditions. However, the Partnership believes thatthe credit risk posed by this industry concentration is offset by thecreditworthiness of the Partnership’s customer base. The Partnership’sportfolio of accounts receivable is comprised primarily of mid-size to largedomestic corporate entities.

*Allowance forDoubtful Accounts*

The Partnership extendscredit to customers and other parties in the normal course of business. Estimatedlosses on accounts receivable, if any, are provided through an allowance fordoubtful accounts. 

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

Inevaluating the level of established reserves, the Partnership makes judgmentsregarding each party’s ability to make required payments, economic events andother factors. As the financial condition of any party changes, circumstancesdevelop, or additional information becomes available, adjustments to theallowance for doubtful accounts may be required. Management of the Partnershiphas established various procedures to manage its credit exposure includinginitial credit approvals, credit limits and rights of offset. The Partnershipmay also use prepayments and guarantees to limit credit risk to ensure thatmanagement’s established credit criteria are met. As of December 31, 2005and 2004, the Partnership has not established an allowance for doubtfulaccounts.

*Property andEquipment*

Property and equipment consist of gas gatheringsystems and other related facilities, which are carried at cost less accumulateddepreciation. The Partnership charges repairs and maintenance against incomewhen incurred and capitalizes renewals and betterments, which extend the usefullife or expand the capacity of assets. The Partnership calculates depreciationusing the straight-line method principally over 15-year and 20-yearestimated useful lives of the Partnership’s assets. The weighted average usefullife of the Partnership’s pipeline and equipment assets is approximately15 years.

The Partnership reviews long-lived assets forimpairment whenever there is evidence that the carrying value of such assetsmay not be recoverable. This review consists of comparing the carrying value ofthe asset with the asset’s expected future undiscounted cash flows withoutinterest costs. An impairment loss would be recognized when estimated futurecash flows expected to result from the use of the asset and its eventualdisposition is less than the asset’s carrying value. Estimates of expectedfuture cash flows represent management’s best estimate based on reasonable andsupportable assumptions.

Asset retirementobligations (“AROs”) are legal obligations associated with the retirement oftangible long-lived assets that result from acquisition, construction,development and/or normal operation of an asset. The Partnership records thefair value of a liability for any legal obligations associated with the AROs inthe period in which the obligation is incurred and can be reasonably estimated.When the liability is initially recorded, a corresponding increase in thecarrying amount of the related long-lived asset is recorded. Over time,accretion of the liability to its present value is recognized each period, andthe capitalized cost is depreciated over the useful life of the related asset. Uponsettlement of the liability, the Partnership either settles the obligation forits recorded amount or incurs a gain or loss on settlement. In December 2005,the Partnership adopted the Financial Accounting Standards Board (“FASB”)Interpretation No (“FIN”) 47, *“Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143.”*whichrequired the Partnership to record a liability for AROs in which the timingand/or amount of settlement of the obligation are uncertain. These conditionalasset retirement obligations were not addressed in Statement of FinancialAccounting Standards (“SFAS”) No. 143, *“Accountingfor Asset Retirement Obligations,”* which the Partnership adopted on January 1,2003. The Partnership adopted FIN 47 effective December 31, 2005 andthe adoption of FIN 47 did not have a significant impact on thePartnership’s financial position, results of operations or cash flows. SeeNote 4.

*Transportation andExchange Imbalances*

In the course oftransporting natural gas for others, the Partnership may receive for redeliverydifferent quantities of natural gas than the quantities actually redelivered. Thesetransactions result in transportation and exchange imbalance receivables orpayables that are recovered or repaid through the 

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

receiptor delivery of natural gas in future periods, if not subject to cash outprovisions. Imbalance receivables are included in accounts receivable andaccounts receivable from affiliates and imbalance payables are included inaccounts payable and accounts payable to affiliates on the balance sheets andare valued at estimated settlement prices or marked-to-market using currentmarket prices in effect for the reporting period of the outstanding imbalances.As of December 31, 2005 and 2004, the Partnership had imbalancereceivables totaling $1,551,014 (unaudited) and $1,850,697, respectively, andimbalance payables totaling $1,952,866 (unaudited) and $2,003,253, respectively.Changes in market value and the settlement of any such imbalance at a pricegreater than or less than the recorded imbalance results in either an upward ordownward adjustment, as appropriate, to the cost of natural gas sold.

*Revenue Recognition*

The Partnership’s natural gas and condensate sales arerecognized in the period when the physical product is delivered to the customerat contractually agreed-upon pricing.

Transportation revenue isrecognized in the period when the service is provided.

*Derivatives*

SFAS No. 133, asamended, *“Accounting for Derivative Instruments and HedgingActivities,”* establishes accounting and reporting standards forderivative instruments, including certain derivative instruments embedded inother contracts, and for hedging activities. SFAS No. 133 requires that anentity recognize all derivatives as either assets or liabilities in thestatement of financial position and measure those instruments at fair value. SFASNo. 133 provides that normal purchases and normal sales contracts are notsubject to the statement. Normal purchases and normal sales are contracts thatprovide for the purchase or sale of something other than a financial instrumentor derivative instrument that will be delivered in quantities expected to beused or sold by the reporting entity over a reasonable period in the normalcourse of business. The Partnership’s forward natural gas purchase and salescontracts are designated as normal purchases and sales. Substantially allforward contracts fall within a one-month to five-year term.

*Income Taxes*

The Partnership is not ataxpaying entity for federal and state income tax purposes and, accordingly,does not recognize any expense for such taxes. The income tax liabilityresulting from the Partnership’s operations is the responsibility of theindividual general partners of the Partnership. In the event of an examinationof the Partnership’s tax return, the tax liability of the individual generalpartners could be changed if an adjustment of the Partnership’s income or lossis ultimately sustained by the taxing authorities.

**Note 3—NewAccounting Pronouncements**

*Exchanges of NonmonetaryAssets an amendment of APB No. 29.*

In December 2004, theFASB issued SFAS No. 153, *“Exchanges of NonmonetaryAssets an amendment of APB Opinion No. 29.”*  This statement amends Accounting PrinciplesBoard Opinion No. 29 to eliminate the exception for nonmonetary exchangesof similar productive assets and replaces it with a general exception forexchanges of nonmonetary assets that do not have commercial substance. Thestatement specifies that a nonmonetary exchange has commercial substance if thefuture cash flows of the entity are 

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

expectedto change significantly as a result of the exchange. The Partnership adoptedthis statement beginning July 1, 2005. The adoption of this statement hadno impact on the Partnership’s previously issued financial statements and isnot expected to have a material impact on future financial statements.

*Accounting Changesand Error Corrections*

In May 2005, the FASBissued SFAS No. 154, *“Accounting Changes andError Corrections.”* SFAS No. 154 requires companies to recognize changes inaccounting principle, including changes required by a new accountingpronouncement when the pronouncement does not include specific transitionprovisions, retrospectively to prior periods’ financial statements. SFAS No. 154is effective for accounting changes and corrections of errors made in fiscalyears beginning after December 15, 2005. The Partnership does not believethat the adoption of SFAS No. 154 will have a material effect on itsfinancial position or results of operations.

*Accounting forPurchases and Sales of Inventory with the Same Counterparty*

In September 2005,the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on theissue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13,*“Accounting for Purchases and Sales of Inventorywith the Same Counterparty”* (Issue 04-13). As part of Issue 04-13,the EITF is requiring that all buy/sell arrangements be reflected on a netbasis, such that the purchase and sale are netted and shown as either a netpurchase or a net sale in the income statement. This requirement is effectivefor new arrangements entered into after March 31, 2006. The Partnership doesnot expect that the adoption of Issue 04-13 will have a material effecton its financial position, results of operations or cash flows.

**Note 4—Propertyand Equipment and Asset Retirement Obligations**

Propertyand equipment consisted of the following:

| ** **                                      | ** ** | **December 31,** | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|
| ** **                                      | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                      | ** ** | **(unaudited)**       | ** ** | ** ** | ** ** |
| Property and  equipment, at cost:               |       |                  |       |   |   |
| Pipelines and equipment                         |       | $                     | 25,461,503 |   | $ | 25,143,074 |   |
| Construction in progress                        |       | 192,307               |       | 60,625 |   |
|                                            |       | 25,653,810            |       | 25,203,699 |   |
| Less accumulated  depreciation and amortization |       | (17,621,916           | )          | (16,920,364 | ) |
| Total property  and equipment, net              |       | $                     | 8,031,894  |   | $ | 8,283,335 |   |

 

*Assetretirement obligations.*   The Partnership hasrecorded asset retirement obligations related to (i) rights-of-way andeasements over property not owned by the Partnership and (ii) regulatoryrequirements triggered by the abandonment or retirement of certain of theseassets. In December 2005, the Partnership adopted FIN 47 and recordeda $44,386 liability in connection with conditional asset retirement obligations.The cumulative effect of this change in accounting principle for years prior to2005 was not significant. None of the Partnership’s assets are legallyrestricted for purposes of settling asset retirement obligations.

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

Thefollowing table presents information regarding the Partnership’s assetretirement obligations.

| Asset retirement  obligation liability balance, December 31, 2004 |   | $      | — |   |
|------------------------------------------------------------------------|--------|--------|--------|--------|
| Adoption of FIN  47 for conditional obligations                        |   | 44,386 |   |
| Asset retirement  obligation liability balance, December 31, 2005 |   | $      | 44,386 |   |

 

Property and equipment at December 31,2005 and 2004 includes $33,842 and $0, respectively, of asset retirement costscapitalized as an increase in the associated long-lived asset. Also, based oninformation currently available, the Partnership estimates that accretionexpense will approximate $3,000 for 2006, $4,000 for each of 2007, 2008, 2009and 2010.

**Note 5—Risk Management Activities**

The Partnership mayutilize a hedging strategy to mitigate the risk of the volatility of natural gasprices in connection with the purchase or sale of natural gas with respect tothe resolution of its natural gas imbalance positions. However, for the yearsended December 31, 2005 (unaudited), 2004 and 2003 (unaudited), no suchhedging positions were purchased or exercised and no option positions wereoutstanding as of December 31, 2005 (unaudited) or 2004.

**Note 6—Related Party Transactions**

*Operations Services*

The Partnership does not directly employ any personsto manage or operate its business. Through December 31, 2004,Copano/Operations, Inc. (“Copano Operations”), an entity controlled by Mr. JohnR. Eckel, Jr., Chairman of the Board of Directors and Chief ExecutiveOfficer of CE, provided these management and operations support services aswell as administrative support services to CWDPL, the operator of thePartnership. Effective January 1, 2005, Copano Operations transferredresponsibility to CPNO Services, L.P. (“CPNO Services”), an indirectwholly-owned subsidiary of CE, for a significant portion of the services thatCopano Operations had previously provided to CWDPL. CWDPL reimbursed CopanoOperations and CPNO Services for all direct and indirect costs of servicesprovided by Copano Operations and CPNO Services. CWDPL charges the Partnershipfor operations and support services as well as a monthly administrative fee of$16,000 and is reimbursed by the Partnership for certain personnel services notincluded in the administrative fee. Additionally, CWDPL has made advances tothe Partnership for capital expenditures. For the years ended December 31,2005, 2004 and 2003, CWDPL charged the Partnership $560,807 (unaudited),$711,593 and $619,743 (unaudited), respectively, for administrative fees andoperations and support services including payroll and benefits expense for bothfield and administrative personnel of the Partnership and capitalized costs. Asof December 31, 2005 and 2004, the Partnership’s net payable to CWDPLtotaled $516,658 (unaudited) and $940,928, respectively.

Management estimates thatthese expenses on a stand-alone basis (that is, the cost that would havebeen incurred by the Partnership to conduct current operations if thePartnership had obtained these services from an unaffiliated entity) would notbe less favorable than the amounts recorded in the Partnership’s financialstatements for the years ended December 31, 2005, 2004 and 2003.

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

*Natural GasTransportation and Exchange Imbalance Transactions*

Pursuant to a gas gathering agreement, the Partnershipearned transportation fees of $474,817 (unaudited), $492,590 and $180,928(unaudited) from Copano Field Services/Agua Dulce (“CFS/AD”), an indirectwholly-owned subsidiary of CE and an affiliate of CWDPL, during the years endedDecember 31, 2005, 2004 and 2003, respectively. The Partnership recordednatural gas sales of $2,142,277 (unaudited), $1,330,993 and $913,332(unaudited) pursuant to the imbalance cash out provisions of the gas gatheringagreement with CFS/AD during the years ended December 31, 2005, 2004 and2003, respectively. Additionally, the Partnership recorded cost of natural gassold of $833,399 (unaudited), $1,135,402 and $459,860 (unaudited) pursuant tothe cash out provisions of the gas gathering agreement with CFS/AD for theyears ended December 31, 2005, 2004 and 2003, respectively. CFS/AD paidthe Partnership $67,033 in well connection fees during the year ended December 31,2005. As of December 31, 2005, CFS/AD owed the Partnership $423,237(unaudited) under this gas gathering agreement and as of December 31,2004, the Partnership owed CFS/AD $200,406 under this gas gathering agreement.

Pursuant to gas purchase and sales agreements, thePartnership sold natural gas to other affiliates of CWDPL and indirectwholly-owned subsidiaries of CE of $1,733,421 (unaudited), $787,117 and $40,833(unaudited) during the years ended December 31, 2005, 2004 and 2003,respectively. Additionally, the Partnership recorded cost of natural gas soldto these other affiliates of CWDPL of $37,882 (unaudited), $550,733 and $9,571(unaudited) during the years ended December 31, 2005, 2004 and 2003,respectively. The Partnership also earned transportation fees from these otheraffiliates of CWDPL of $0 (unaudited), $1,575, $0 (unaudited) during the yearsended December 31, 2005, 2004 and 2003, respectively. As of December 31,2005, the other affiliates of CWDPL owed the Partnership $169,010.

Pursuant to gas gathering agreements with the othergeneral partners of the Partnership, the Partnership earned transportation feesof $153,959 (unaudited), $146,647 and $104,570 (unaudited) during the yearsended December 31, 2005, 2004 and 2003, respectively. Additionally, underone of the other general partner’s gas gathering agreement, the Partnershiprecorded gas imbalance activity as cost of natural gas sold of $(393,597)(unaudited), $(111,288) and $438,368 (unaudited) during the years ended December 31,2005, 2004 and 2003, respectively. Under one of the other general partner’s gasgathering agreement, the Partnership had net purchases of natural gas of $66,390(unaudited), $41,752 and $0 (unaudited) during the years ended December 31,2005, 2004 and 2003, respectively. As of December 31, 2005 and 2004, thesegeneral partners owed the Partnership $38,760 (unaudited) and $41,973,respectively, for transportation fees. Additionally, one of these generalpartners paid a well connection fee of $23,000 during the year ended December 31,2004. The Partnership had net gas imbalance obligations to these generalpartners of $361,805 (unaudited) and $755,915 as of December 31, 2005 and2004, respectively.

Management of thePartnership believes these transactions were on terms no less favorable thanthose that could have been achieved with an outside company.

**Note 7—BusinessSegment and Customer Information**

Based on its management approach, the Partnershipbelieves that all of its material operations revolve around the gathering andtransportation of natural gas and it currently reports its operations, bothinternally and externally, as a single business segment. The Partnership hadtwo (unaudited) affiliated customers that accounted for 39% (unaudited) and 25%(unaudited), respectively, of its revenue for the year ended December 31,2005. The Partnership had two affiliated customers and one third-partycustomer 

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

that accounted for 40%,17% and 15%, respectively, of its revenue for the year ended December 31,2004. The Partnership had one (unaudited) affiliated customer and one(unaudited) third-party customer that accounted for 34% (unaudited) and27% (unaudited), respectively, of its revenue for the year ended December 31,2003.

Excluding changes in thegas imbalances recorded as cost of natural gas sold, the Partnership had one(unaudited) third-party and one (unaudited) affiliated supplier duringthe year ended December 31, 2005 that accounted for 73% (unaudited) and24% (unaudited), respectively, of its cost of natural gas sold. Excludingchanges in the gas imbalances recorded as cost of natural gas sold, thePartnership had one third-party and two affiliated suppliers during theyear ended December 31, 2004 that accounted for 38%, 34% and 17%,respectively, of its cost of natural gas sold. Excluding changes in the gasimbalances recorded as cost of natural gas sold, the Partnership had one(unaudited) third-party supplier and one (unaudited) affiliated supplierfor the year ended December 31, 2003 that accounted for 78% (unaudited)and 21% (unaudited), respectively, of its cost of natural gas sold. ThePartnership only buys and sells natural gas in connection with the resolutionof natural gas imbalances incurred as a result of its gathering andtransportation activities.

**Note 8—FairValue of Financial Instruments**

The carrying amount ofcash equivalents is believed to approximate its fair value because of the shortmaturities of these instruments.

**Note 9—Commitmentsand Contingencies**

*Commitments*

For the years ended December 31, 2005, 2004 and2003, rental expense for leased vehicles and leased compressors and relatedfield equipment used in the Partnership’s operations totaled $159,667(unaudited), $180,269 and $186,950 (unaudited), respectively. As of December 31,2005, commitments under the Partnership’s lease obligations totaled $35,725 for2006, $28,031 for 2007 and $5,575 for 2008.

Although the Partnershipmay have both fixed and variable contractual commitments arising in theordinary course of its activities, as of December 31, 2005, thePartnership had no fixed or variable contractual commitments to purchase orsell natural gas.

*Guarantees*

In November 2002, the FASB issued FIN 45, *“Guarantor’s Accounting and Disclosure Requirements for Guarantees,Including Indirect Guarantees of Indebtedness of Others.”*  In certain instances, this interpretationrequires a guarantor to recognize, at the inception of a guarantee, a liabilityfor the fair value of the obligation undertaken in issuing the guarantee.

FIN 45also sets forth disclosure requirements for guarantees including the guaranteesby a general partner of the Partnership on behalf of the Partnership. CWDPLguaranteed certain trade obligations of the Partnership and as of December 31,2005, the balance of these guaranteed obligations was less than $150,000. However,from July 8, 2002 through April 1, 2004, subsidiaries of CEguaranteed certain vehicle lease obligations of Copano Operations for vehiclesoperated for the benefit of the Partnership and certain subsidiaries of CE. EffectiveApril 2, 2004, the vehicle lease was transferred to a subsidiary of CE, as

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS (Continued)**

 

lessee. As of December 31, 2005, certain othersubsidiaries of CE guaranteed approximately $178,000 of the lessee’s leasepayment obligations (approximately $69,000 relates to vehicles used by thePartnership). Additionally, under each vehicle lease, the lessee has guaranteedthe lessor a minimum residual sales value upon the expiration of the lease andsale of the underlying vehicle. These residual sale values guaranteed by thelessee are in turn guaranteed by certain other subsidiaries of CE. At December 31,2005, guaranteed residual values for vehicles used by the Partnership underthese operating leases were as follows:

| ** **             | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Lease residual  values |       |     | $          | —   |       |     | $          | 13,654   |       | $              | 23,661     |      |       | $ | — |   |   |   | $ | — |   |   | $ | 37,315 |   |
|                        |            |          |            |          |            |          |            |          |            |                |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

Presently, neither thePartnership nor any of its general partner has any other types of guaranteesoutstanding that require liability recognition under the provisions of FIN 45.

*RegulatoryCompliance*

In the ordinary course ofbusiness, the Partnership is subject to various laws and regulations. In theopinion of management, compliance with existing laws and regulations will notmaterially affect the financial position of the Partnership.

*Litigation*

Although the Partnershipmay, from time to time, be involved in litigation and claims arising out of itsoperations in the normal course of business, the Partnership is not currently aparty to any material legal proceedings. In addition, management of thePartnership is not aware of any material legal or governmental proceedingsagainst the Partnership, or contemplated to be brought against the Partnership,under the various environmental protection statutes to which the Partnership issubject, that would have a significant adverse effect on the Partnership’sfinancial position or results of operations.

**Note 10—SupplementalDisclosures to the Statements of Cash Flows**

*Supplemental disclosures of noncash investing andfinancing activities*

| ** **                                 | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                 | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                 | ** ** | **(unaudited)**                            | ** ** | ** ** | ** ** | **(unaudited)** | ** ** |
| Increase in  property, plant and equipment |       |                                       | $          | 33,842 |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Increase in other  noncurrent liabilities  |       |                                       | 44,386     |   |   |   | — |   |   |   | — |   |   |

 

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