**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

**Form 10-K**

**x**                              AnnualReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**forthe fiscal year ended December 31, 2004**

**OR**

**o**                                 TransitionReport Pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**forthe transition period from                  to                  **

**Commissionfile number: 001-32329**

**COPANO ENERGY, L.L.C.**

(Exact name of registrantas specified in its charter)

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

**(713)621-9547**

(Registrant’s telephonenumber, including area code

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

|      | **Title of Each Class** | ** ** | ** ** | **Name of Exchange on which Registered** | ** ** |
|------|-------------------------|------------|------------|------------------------------------------|------------|
| None | Not applicable          |

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OFTHE ACT:

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

Indicate by check markwhether registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. Yes x Noo

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, andwill not be contained, to the best of registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. x

The aggregate market value of our voting andnon-voting common equity held by non-affiliates of the registrant wasapproximately $163,875,000 on December 31, 2004, based on $28.50 per unit,the last reported sale price of the Common Units as reported on The NASDAQ NationalMarket on such date.

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

As of March 28, 2005,there were outstanding 7,066,192 Common Units and 3,519,126 Subordinated Units.

**DOCUMENTSINCORPORATED BY REFERENCE:**
| **Part III****of****Form 10-K** | Portions of the Proxy  Statement for the Annual Meeting of Unitholders of Copano Energy, L.L.C. to  be held June 7, 2005 are incorporated by reference into Part III of  this Annual Report on Form 10-K (to be filed with the Securities and  Exchange Commission prior to May 1, 2005). |
|-------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

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**TABLE OF CONTENTS**
|                   | ** ** | ** **                                                                                                          | ** ** | **Page** |
|-------------------|------------|---------------------------------------------------------------------------------------------------------------------|------------|----------|
| **Part I**   |       |                                                                                                                |       |     |
| Item 1.           |       | Business                                                                                                            |       | 1        |
| Item 2.           |       | Properties                                                                                                          |       | 21       |
| Item 3.           |       | Legal  Proceedings                                                                                                  |       | 21       |
| Item 4.           |       | Submission  of Matters to a Vote of Security Holders                                                                |       | 21       |
| **Part II**  |       |                                                                                                                |       |     |
| Item 5.           |       | Market  for Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities |       | 22       |
| Item 6.           |       | Selected  Financial Data                                                                                            |       | 24       |
| Item 7.           |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operation                          |       | 28       |
| Item 7A.          |       | Quantitative  and Qualitative Disclosures About Market Risk                                                         |       | 54       |
| Item 8.           |       | Financial  Statements and Supplementary Data                                                                        |       | 54       |
| Item 9.           |       | Changes  in and Disagreements With Accountants on Accounting and Financial Disclosure                               |       | 54       |
| Item 9A.          |       | Controls  and Procedures                                                                                            |       | 55       |
| Item 9B.          |       | Other  Information                                                                                                  |       | 55       |
| **Part III** |       |                                                                                                                |       |     |
| Item 10.          |       | Directors  and Executive Officers of the Registrant                                                                 |       | 56       |
| Item 11.          |       | Executive  Compensation                                                                                             |       | 56       |
| Item 12.          |       | Security  Ownership of Certain Beneficial Owners and Management and Related Unitholder  Matters                     |       | 56       |
| Item 13.          |       | Certain  Relationships and Related Transactions                                                                     |       | 56       |
| Item 14.          |       | Principal  Accountant Fees and Services                                                                             |       | 56       |
| **Part IV**  |       |                                                                                                                |       |     |
| Item 15.          |       | Exhibits  and Financial Statement Schedules                                                                         |       | 57       |

 

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**PART I**

*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. We completed our initial public offering on November 15,2004 and our common units are listed on The NASDAQ National Market under thesymbol “CPNO.” Our business activities are primarily conducted through whollyowned subsidiaries. References in this Annual Report to “Copano Energy, L.L.C.,”“we,” “our,” “us,” or like terms refer to Copano Energy, L.L.C. and itsconsolidated subsidiaries.

We are a growth-oriented midstream energycompany with networks of natural gas gathering and intrastate transmissionpipelines in the South Texas and Texas Gulf Coast regions. Our natural gasprocessing plant is the second largest in the Texas Gulf Coast region and thethird largest in Texas in terms of throughput capacity. Our natural gaspipeline assets consist of approximately 1,366 miles of gas gathering andtransmission pipelines, including 144 miles of pipeline owned by a partnershipin which we own a 62.5% interest and which we operate. These pipelines collectnatural gas from designated points near producing wells and transport thesevolumes to third-party pipelines, our Houston Central Processing Plant,utilities and industrial consumers.

Our Houston Central Processing Plant is locatedapproximately 100 miles southwest of Houston and has the capacity to processapproximately 700 million cubic feet of gas per day, or MMcf/d. Volumesshipped to our processing plant, either on our pipelines or a third-partypipeline, are treated to remove contaminants and conditioned or processed toextract mixed natural gas liquids, or NGLs. Processed or conditioned naturalgas is then delivered to third-party pipelines through plantinterconnects, while NGLs are fractionated or separated and then sold ascomponent NGL products, including ethane, propane, isobutane, normal butane,natural gasoline and stabilized condensate. We also own a 104-mile NGL productspipeline extending from the Houston Central Processing Plant to the Houstonarea.

We have two operatingsegments: Copano Pipelines, which performs our natural gas gathering andtransmission and related operations, and Copano Processing, which performs ournatural gas processing, treating and conditioning and related NGLtransportation operations. Please read Item 7, “Management’s 

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Discussionand Analysis of Financial Condition and Results of Operation—Our Results ofOperation” and Note 17 to the Consolidated Financial Statements, “SegmentInformation” contained in Item 8 of this Annual Report for more detaileddescriptions of the financial results of our operating segments.

**Business Strategy**

Our management teamis committed to increasing the amount of cash available for distribution byimproving the cash flows from our existing assets, pursuing complementaryacquisition and expansion opportunities and maintaining an appropriate mix ofindex-related and fixed-fee margin business to stabilize our cash flow. Keyelements of our strategy include the following:

·       *Increase cash flows from our existing assets.  *Ourpipelines have excess capacity, which provides us with opportunities toincrease throughput volume with minimal incremental costs. We intend toincrease cash flows from our existing assets by aggressively marketing ourservices to producers to connect new supplies of natural gas, increase volumesand more fully utilize our capacity.

·       *Pursue complementary acquisitions,**expansion and asset enhancement opportunities.  *We intend to continue tomake complementary acquisitions of midstream assets in our operating areas thatprovide opportunities to expand either the acquired assets or our existingassets to increase utilization. We pursue acquisitions that we believe willallow us to capitalize on our existing infrastructure, personnel, and producerand customer relationships to provide an integrated package of services. Forexample, after our acquisition and integration of our Karnes County GatheringSystem, we acquired the Runge Gathering System and with some modifications andenhancements, attached it to the Karnes County Gathering System. These pipelineacquisitions allowed us to deliver additional natural gas to our HoustonCentral Processing Plant.

·       *Exploit the operating flexibility of our assets*.   Exploitingour ability to condition gas, rather than fully process it, provides us withsignificant benefits during periods when fully processing natural gas is noteconomic. We intend to monitor natural gas and NGL prices to quickly switchbetween processing and conditioning modes at our Houston Central ProcessingPlant when it is economically appropriate to do so. We will also continue totake advantage of multiple residue outlets at our Houston Central ProcessingPlant and multiple inlet supply points in our Upper Gulf Coast Region.

·       *Enter into contracts that provide us with positive operating marginsunder a variety of market conditions*.   Because of thesignificant volatility of natural gas and NGL prices, we attempt to structureour contracts in a manner that allows us to achieve positive gross margins fromour contracts in a variety of market conditions. In our processing contracts,we focus on arrangements pursuant to which we are paid a fee to conditionnatural gas when processing is economically unattractive. In our contracts withproducers, we focus on arrangements pursuant to which the fee received for theservices we deliver is sufficient to provide us with positive operating marginsirrespective of NGL prices. Collectively, this strategy should provide us witha more predictable revenue stream.

·       *Expand our geographic scope into new regions where our growth strategycan be applied.  *We intend to pursue opportunities to acquireassets in new regions where we believe growth opportunities are attractive andour business strategies can be successfully applied.

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Wehave set forth in the table below summary information describing the regions inwhich we have pipeline systems and processing assets.
| ** **                        | ** ** | ** **                                                 | ** ** | ** **         | ** **          | ** **                            | ** ** | ** **          | ** ** | **Average**                                    | ** ** | **Year Ended  December 31,  2004 **            | ** ** |
|-----------------------------------|------------|------------------------------------------------------------|------------|--------------------|---------------------|---------------------------------------|------------|---------------------|------------|------------------------------------------------|------------|---------------------------------------------------------------|------------|
| **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** | ** ** |
| **Copano  Pipelines**             |       |                                                       |       |               |                |                                  |       |                |       |                                           |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **South  Texas Region**           |       |                                                       |       |               |                |                                  |       |                |       |                                           |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Live Oak Area                     |       | Gathering                                                  |       |               | May 2002       |                                  |       |                | 112        |                                           |       |                                                          | 102,000    |   |   |   | 9,179 |   |   |   | 23,280 |   |   |   | 23 | % |   |
| Agua Dulce Area(4)                |       | Gathering and  Transmission                           |       |               | June 1996      |                                  |       |                | 381        |                                           |       |                                                          | 78,000     |   |   |   | 7,850 |   |   |   | 32,399 |   |   |   | 42 | % |   |
| Hebbronville Area                 |       | Gathering                                                  |       |               | September 1994 |                                  |       |                | 79         |                                           |       |                                                          | 90,000     |   |   |   | 15,337 |   |   |   | 29,423 |   |   |   | 33 | % |   |
| Karnes Area                       |       | Gathering                                                  |       |               | August 2004    |                                  |       |                | 68         |                                           |       |                                                          | 17,500     |   |   |   | 2,000 | (5) |   |   | 9,771 |   |   |   | 56 | % |   |
| Webb/Duval  Area(6)(7)            |       | Gathering                                                  |       |               | February 2002  |                                  |       |                | 144        |                                           |       |                                                          | 219,000    |   |   |   | 43,046 |   |   |   | 104,437 |   |   |   | 48 | % |   |
| **Coastal  Waters Region**        |       | Gathering                                                  |       |               | June 1992      |                                  |       |                | 142        |                                           |       |                                                          | 37,000     |   |   |   | 1,208 |   |   |   | 11,403 |   |   |   | 31 | % |   |
| **Central  Gulf Coast  Region**   |       | Gathering                                                  |       |               | August 2001    |                                  |       |                | 210        |                                           |       |                                                          | 155,000    |   |   |   | 118,804 |   |   |   | 74,475 |   |   |   | 48 | % |   |
| **Upper  Gulf Coast  Region**     |       |       Gathering and  Transmission |       |               | April 1997     |                                  |       |                | 230        |                                           |       |                                                          | 139,000    |   |   |   | 33,748 |   |   |   | 40,219 |   |   |   | 29 | % |   |
| Total                             |       |                                                       |       |               |                |                                  |       |                | 1,366      |                                           |       |                                                          |       |   |   |   |   |   |   |   | 325,407 |   |   |   |   |   |   |
| **Copano Processing**             |       |                                                       |       |               |                |                                  |       |                |       |                                           |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Houston Central  Processing Plant |       | Processing                                                 |       |               | August 2001    |                                  |       |                |       |                                           |       |                                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Inlet volumes                     |       |                                                       |       |               |                |                                  |       |                |       |                                           |       |                                                          |       |   |   |   | 626,764 | (8) |   |   | 529,040 |   |   |   |   |   |   |
| NGLs produced                     |       |                                                       |       |               |                |                                  |       |                |       |                                           |       |                                                          |       |   |   |   | 10,406  Bbls/d | (8) |   |   | 15,373 |   |   |   |   |   |   |
| Sheridan NGL  Pipeline       |       | NGL  Transportation                                        |       |               | August 2001    |                                  |       |                | 104        |                                           |       |                                                          |       |   |   |   | 2,648  Bbls/d | (8) |   |   | 4,322 |   |   |   |   |   |   |
|                                   |            |                                                            |            |                    |                     |                                       |            |                     |            |                                                |            |                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)             The initial acquisition date is the datethat we first commenced operations with respect to any area, region andfacility.

(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 32,816 Mcf/d and 42%, respectively, for the year ended December 31,2004.

(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. Throughput volumes for Webb/Duval are presented on a gross basis,without netting volumes attributable to each of the partners.

(7)             Throughput volumes presented in the table are net ofaffiliate transactions. Gross volumes and utilization of capacity in this areatotaled 126,305 Mcf/d and 58%, respectively, for the year ended December 31,2004.

(8)             Represents volumes for the month of June 2001.In July 2001, volumes began to be transported from our South Texas Regionto the KMTP Laredo-to-Katy pipeline thereby increasing the volume of NGLsproduced by our Houston Central Processing Plant and transported on ourSheridan NGL line.

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**Copano Pipelines**

We own approximately 1,366miles of pipelines used for natural gas gathering and transmission, includingapproximately 144 miles of pipeline owned by a partnership in which we own a62.5% interest. For the years ended December 31, 2004 and 2003, weaveraged net throughput volumes of 325,407 Mcf/d and 334,142 Mcf/d,respectively, of natural gas. Our facilities are operated in four separateoperating regions as described below.

**South Texas Region**

The South Texas Regionconsists of eight wholly owned gathering and intrastate transmission systemstotaling approximately 640 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. Thisregion 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.

*Live Oak System.  *TheLive Oak System is an approximately 54-mile pipeline system that gathersnatural gas from fields located in Live Oak County, Texas. The Live Oak Systemis composed of a 12-inch diameter mainline and two 8-inch diametermain gathering lateral lines, the Bennett lateral and the Patteson lateral,which extend into southern and eastern Live Oak County. The system alsoincludes several smaller lines that range in size from two inches to eightinches in diameter. We currently gather natural gas from approximately 29active receipt points representing 12 producers and three shippers connected toour Live Oak System. All of the natural gas from the Live Oak System iscompressed, dehydrated and delivered to the KMTP Laredo-to-Katy pipeline fortreating, conditioning and/or processing at our Houston Central ProcessingPlant.

In February 2002, we expanded our compression anddehydration facilities providing a throughput capacity of 50,000 Mcf/d. Wecurrently operate 2,060 horsepower of compression and 40,000 Mcf/d ofdehydration capacity. Average throughput volume on this system was 21,278 Mcf/dfor the year ended December 31, 2004, up from 18,917 Mcf/d for the yearended December 31, 2003.

*Clayton Pipeline.  *TheClayton Pipeline is an approximately 58-mile pipeline extending throughAtascosa, Live Oak and Duval Counties, Texas. The northern 34 miles consists of10-inch diameter pipeline and the southern 22 miles consists of 16-inchdiameter pipeline. There are approximately two miles of 3-inch to 6-inchdiameter feeder pipelines. We currently transport natural gas on the ClaytonPipeline from seven active receipt points including the Pueblo MidstreamFashing plant in Atascosa County, representing four producers as well as theFashing plant tailgate interconnect. All natural gas is delivered to HoustonPipe Line Company (an affiliate of Energy Transfer Partners, L.P.). We haverecently completed a pipeline interconnect that will be used to transportnatural gas for a third party, which we anticipate to begin flowing during thesecond quarter of 2005. There is an existing inactive interconnect with NaturalGas Pipeline Company of America, or NGPL, on the southern end of the ClaytonPipeline. The Clayton Pipeline has no compression or dehydration facilities.

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Average throughput volumeon the Clayton Pipeline was 2,002 Mcf/d for the year ended December 31,2004 and 4,736 Mcf/d for the year ended December 31, 2003. The ClaytonPipeline has a capacity 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.

*Agua Dulce System.  *TheAgua Dulce System is an approximately 240-mile gathering system locatedin Duval, Jim Wells and Nueces Counties, Texas. The Agua Dulce System iscomposed of (i) the East Duval lateral, a 17-mile, 10-inchdiameter mainline that originates near Agua Dulce, Texas in Jim Wells County,and terminates at an interconnect with the Webb/Duval Gathering System and (ii) severaldistinct gathering systems that deliver natural gas to the East Duval lateral. Thereare approximately 240 miles of 2-inch to 12-inch diameter gatheringpipelines that supply the East Duval lateral. We currently gather natural gasfrom 41 active receipt points, representing 25 producers and one shipper. Sincepurchasing the system, we have added approximately 9 miles of pipeline,including the 6-mile, 12-inch diameter line that connected thesystem to the Webb/Duval Gathering System in 2002. We currently have 5,525horsepower of compression and 44,000 Mcf/d of dehydration capacity installed onthis system. Natural gas is gathered and transported through the Agua DulceSystem into the Webb/Duval Gathering System, which can deliver this natural gasinto the KMTP Laredo-to-Katy pipeline. The Agua Dulce System has inactiveinterconnects with GulfTerra Energy Partners (a subsidiary of EnterpriseProducts Partners, L.P.), Humble Gas Pipeline Company (an affiliate ofExxonMobil), and Duke Energy Field Services.

Average net throughput volume on this system was22,196 Mcf/d for the year ended December 31, 2004, up from 7,429 Mcf/d forthe year ended December 31, 2003. The Agua Dulce System has an estimatedcapacity of 37,000 Mcf/d.

*Nueces County System.  *TheNueces County System is an approximately 141-mile pipeline system thatgathers natural gas in Nueces and San Patricio Counties, Texas. The NuecesCounty System is composed of gathering and transmission lines ranging in sizefrom two inches to 12 inches in diameter. The Nueces County System currentlygathers natural gas from 17 active receipt points representing nine producers. Naturalgas from this system is gathered and delivered to Houston Pipe Line Company (anaffiliate of Energy Transfer Partners, L.P.) and to our Agua Dulce System. Wecurrently have 85 horsepower of compression and 33,000 Mcf/d of dehydrationcapacity installed on this system.

Average throughput volumeon this system was 10,203 Mcf/d for the year ended December 31, 2004 and15,468 Mcf/d for the year ended December 31, 2003. The Nueces CountySystem has an estimated capacity of 41,000 Mcf/d under current operatingpressures.

*Hebbronville Area*

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

*Mesteña Grande System.  *TheMesteña Grande System is an approximately 56-mile pipeline system locatedin the southern portion of Jim Hogg County and the northern half of DuvalCounty, Texas. The Mesteña Grande System currently gathers natural gas from 18active receipt points, representing five producers and one shipper. This systemconsists of pipelines ranging in size from 4 inches to 8 inches in diameter. Allnatural gas gathered from the Mesteña Grande System is transported for deliveryto KMTP via our Hebbronville Pipeline. We have 4,020 horsepower of compressioninstalled on this system and 80,000 Mcf/d of dehydration capacity.

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*Hebbronville Pipeline.  *TheHebbronville Pipeline was constructed by us in 2001 and is an approximately 23-milepipeline comprised of 12-inch diameter pipeline and 16-inchdiameter pipeline, which transports all of the natural gas from the MesteñaGrande System for delivery to the KMTP Laredo-to-Katy pipeline. TheHebbronville Pipeline has two active receipt points representing one shipper. Thereis no installed compression or dehydration on this pipeline.

Average throughput volumeon these pipelines was 29,423 Mcf/d on a combined basis for the year ended December 31,2004, down from 40,345 Mcf/d for the year ended December 31, 2003. TheMesteña Grande System currently has an estimated capacity of 90,000 Mcf/d andthe Hebbronville Pipeline has an estimated capacity of 250,000 Mcf/d. Withoutadditional compression, however, the combined capacity of these pipelines is limitedto 90,000 Mcf/d.

*Karnes Area*

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

*Karnes County Gathering System.  *TheKarnes County Gathering System is an approximately 15-mile pipelineoperating in northern Bee and southern Karnes Counties, Texas. This system iscomprised of natural gas pipelines ranging in size from 10 inches to 16 inchesin diameter. The Karnes County Gathering System gathers natural gas from oneactive receipt meter connected to a third party. Natural gas transported on theKarnes County Gathering System is delivered to the KMTP Laredo-to-Katypipeline and is processed or conditioned at our Houston Central ProcessingPlant. We have 2,060 horsepower of compression installed on this system. Weacquired this system in August 2004 and initial flow of natural gascommenced on September 10, 2004.

*Runge Gathering System.  *TheRunge Gathering System is comprised of 53 miles of natural gas pipelineslocated in Bee, DeWitt, Goliad and Karnes Counties, Texas and was acquired fromKinder Morgan Tejas Pipeline, L.P. effective December 1, 2004 with ouroperation of the system commencing on that date. The acquisition wasaccomplished at no cost to us (other than transaction and integration 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 are free toattach new supplies of natural gas to the system that we can then sell atmarket prices. This system is comprised of 37 miles of natural gas pipelinesranging in size from 4 inches to 8 inches and a 16-mile 4 inch naturalgas liquids pipeline which was converted to natural gas service to providedelivery of natural gas from the Runge Gathering System to our Karnes CountyGathering System. When we acquired the Runge Gathering System in December 2004,approximately 2,000 Mcf/d was flowing into the Runge Gathering System. Naturalgas from the Runge Gathering System is gathered and redelivered into the KarnesCounty Gathering System which is then delivered to the KMTP Laredo-to-Katypipeline and is processed or conditioned at our Houston Central ProcessingPlant. This system has seven active receipt meters.

Average throughput volumeon these pipelines was 9,771Mcf/d on a combined basis for the period fromacquisition 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 Gatherers, a generalpartnership that we operate and in which we hold a 62.5% interest. Our originalinvestment in the Webb/Duval Area was made in November 2001 when weacquired our initial 15% partnership interest in Webb/Duval Gatherers, which,at the time, only owned the Webb/Duval Gathering System. In February 2002,we acquired an additional 47.5% partnership interest in Webb/Duval Gatherers,and 

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Webb/Duval Gathererspurchased the Olmitos and Cinco Compadres Gathering Systems. As the holder of a62.5% interest in the partnership that owns these pipeline systems, we operatethese systems subject to certain rights of the other partners, including theright to approve capital expenditures in excess of $0.1 million, financingarrangements by the partnership or any expansion projects associated with thesesystems. In addition, each partner has the right to use its pro rata share ofpipeline capacity on these systems subject to applicable ratable take andcommon purchaser statutes.

*Webb/Duval Systems.  *TheWebb/Duval Gathering System is a 121-mile pipeline located in Webb andDuval Counties, Texas, and is comprised of 3-inch and 16-inchdiameter pipelines. Following our construction of a 6-mile, 12-inchdiameter pipeline in 2002, the Webb/Duval Gathering System connects our AguaDulce System to the KMTP Laredo-to-Katy pipeline. We currently have 29 activereceipt points connected to the Webb/Duval Gathering System, representing 13shippers. We currently have 7,468 horsepower of installed compression and nodehydration on this system. The Olmitos Gathering System and the CincoCompadres Gathering System are smaller non-contiguous gathering systems thatare part of Webb/Duval Gatherers’ assets. The Olmitos Gathering System is a 14-milepipeline located in Webb County, Texas, and is comprised of 4-inch to 8-inchdiameter pipelines. The Cinco Compadres Gathering System is a 9-milepipeline located in Webb County, Texas, and is comprised of 3-inch to 6-inchdiameter pipelines.

Average total throughputvolume on these combined systems including volumes delivered by our Agua DulceSystem was 126,305 Mcf/d for the year ended December 31, 2004, up from102,726 Mcf/d for the year ended December 31, 2003. Excluding the volumereceived from our Agua Dulce System described previously, the averagethroughput volume on these systems was 104,437 Mcf/d for the year ended December 31,2004, up from 95,341 Mcf/d. Differences in volumes between the Webb/DuvalGathering Area and the Agua Dulce systems are attributable to gas consumed asfuel during dehydration and compression, ordinary pipeline system gains andlosses and the fact that the Agua Dulce System used alternate interconnectsbefore its connection during 2002 to the Webb/Duval Gathering System. The Webb/DuvalGathering System has an estimated current capacity of 219,000 Mcf/d. Wegenerate gross margins from transportation of natural gas across these majority-ownedpipelines.

**Coastal WatersRegion**

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.

*Copano Bay System.  *TheCopano Bay System currently comprises approximately 119 miles of natural gaspipelines, which range in size from three inches to 12 inches in diameter. Currently,the Copano Bay System gathers natural gas from the offshore Matagorda IslandBlock 721 area, Aransas and Copano Bays, and adjacent onshore lands throughAransas Bay and onshore at Rockport, Texas. Natural gas and condensate areseparated at our Lamar separation and dehydration facility, and the natural gasis delivered to GulfTerra Energy Partners (a subsidiary of Enterprise ProductsPartners, L.P.)/Channel at Lamar, Texas. The condensate is stored andredelivered to producers and shippers who then truck the product to market. TheCopano Bay System gathers or transports substantially all of the natural gas inthe Copano Bay and Aransas Bay area. In 2003, we installed 15,000 Mcf/d ofadditional dehydration capacity (for a total of approximately 25,000 Mcf/d ofdehydration capacity) on the northern end of the Copano Bay System. Thethroughput capacity of this system is 37,000 Mcf/d. The Copano Bay System hasnine active receipt points, representing nine producers and one shipper.

Average throughput volume on this system was 11,403Mcf/d for the year ended December 31, 2004, down from 20,541 Mcf/d for theyear ended December 31, 2003.

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*EncinalChannel Pipeline.  *The Encinal Channel Pipeline is anapproximately 23-mile pipeline that is currently inactive. The EncinalChannel Pipeline measures three inches to 12 inches in diameter and is locatedin Nueces and San Patricio Counties, Texas. The Encinal Channel Pipelinecurrently has an estimated throughput capacity of 145,000 Mcf/d. There is noinstalled compression or dehydration on this pipeline. We believe inland baylease sales will ultimately provide natural gas purchase and transportationopportunities for this pipeline.

**Central Gulf CoastRegion**

The Central Gulf Coast Region is composed of twointrastate natural gas gathering systems totaling approximately 210 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 the our HoustonCentral Processing Plant include KMTP, Tennessee Gas Pipeline, Texas EasternTransmission and Houston Pipe Line Company (an affiliate of Energy TransferPartners, L.P.).

*Sheridan System.  *TheSheridan System consists of approximately 60 miles of natural gas gatheringlines ranging in size from four inches to 10 inches in diameter, and gathersnatural gas from 17 active receipt points and one third-party pipelineinterconnect located in Colorado and Lavaca Counties, Texas, representing 14producers and four shippers. There is no installed compression or dehydrationon this system. Natural gas from the Sheridan System is gathered andtransported to our Houston Central Processing Plant for treatment of carbondioxide, processing and ultimate delivery into the interconnects at thetailgate of our processing plant. The Sheridan System also has a pipelineinterconnect with the Enterprise Products Chesterville System. Averagethroughput volume on this system was 18,338 Mcf/d for the year ended December 31,2004, up from 15,284 Mcf/d for the year ended December 31, 2003. TheSheridan System has an estimated capacity of 45,000 Mcf/d.

*ProvidentCity System.  *This system consists of approximately 150miles of natural gas gathering lines ranging in size from three inches to 14inches in diameter, and gathers natural gas from 65 receipt points and onethird-party pipeline interconnect located in Colorado, DeWitt, Lavaca andWharton Counties, Texas, representing 40 producers and two shippers. There isno compression or dehydration installed on this system. The Provident CitySystem has a pipeline interconnect with Duke Energy Field Services’ San JacintoPipeline System. Average throughput volume on this system was 56,137 Mcf/d forthe year ended December 31, 2004 down from 65,068 Mcf/d for the year endedDecember 31, 2003. The Provident City System has an estimated capacity of110,000 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.

*Sam Houston System.  *TheSam Houston System includes approximately 125 miles of natural gas pipelinethat gathers natural gas and receives natural gas from other pipelines forultimate delivery to markets on the system. This gathering and transportationpipeline ranges in size from four inches to 12 inches in diameter. We currentlygather natural gas from 22 active receipt points and five third-partypipeline interconnects, representing eight producers and five shippers.

The Sam Houston System has interconnects with HoustonPipe Line Company (an affiliate of Energy Transfer Partners, L.P.), Lone StarPipeline Company, KMTP, Vantex Gas Pipeline Company and Texas EasternTransmission. The Sam Houston System delivers natural gas to multipleCenterPoint Energy city gates in The Woodlands, Conroe and Huntsville, Texas,to Universal Natural Gas, a gas company providing services to residentialmarkets in southern Montgomery County, Texas and to Entergy’s Lewis 

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Creek Generating Plant andseveral industrial consumers. There is no compression or dehydration installedon this pipeline system. Average net throughput volume on this system was33,489 Mcf/d for the year ended December 31, 2004, down from 38,449 Mcf/dfor the year ended December 31, 2003. The Sam Houston System has anestimated capacity of approximately 119,000 Mcf/d.

*Grimes County System.  *TheGrimes County System is an approximately 77-mile natural gas gatheringsystem located in Grimes County, Texas, which consists of natural gas pipelinesranging in size from two inches to 12 inches in diameter. We currently gathernatural gas from eight active receipt points representing five producers, anddeliver all of the natural gas to our Sam Houston System. There is 311horsepower of compression and no active dehydration on this pipeline system.

Average throughput volume on this system was 2,514Mcf/d for the year ended December 31, 2004, up from 1,155 Mcf/d for theyear ended December 31, 2003. The Grimes County System has an estimatedcapacity of 23,000 Mcf/d.

*Lake Creek 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 (an affiliate of EnergyTransfer Partners, L.P.) near the Bammel Storage field in Harris County.

The majority of thenatural gas transported on this pipeline is delivered to CenterPoint Energy atdelivery points serving the western portion of The Woodlands, Texas and thesurrounding area. Natural gas is also delivered to Universal Natural Gas. Averagethroughput volume on this system was 4,216 Mcf/d for the year ended December 31,2004, down from 11,409 Mcf/d for the year ended December 31, 2003. TheLake Creek Pipeline has an estimated capacity of 20,000 Mcf/d.

**Copano Processing**

The Copano Processing segment includes our HoustonCentral Processing Plant located near Sheridan, Texas in Colorado County andour Sheridan NGL Pipeline that runs from the tailgate of the processing plantto the Houston area.

*Houston Central Processing Plant.  *OurHouston Central Processing Plant is the third largest in the state of Texas interms of throughput capacity and the second largest and the most fuel efficientprocessing plant in the areas in which we operate. Our Houston CentralProcessing Plant removes NGLs from the natural gas supplied by the KMTPLaredo-to-Katy pipeline, which it straddles, and the pipelines in our CentralGulf Coast Region gathering systems and 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 cryogenic turbo-expandertrain, a 25,000 Bbl/d NGL fractionation facility, and 882,000 gallons ofstorage capacity for propane, butane and natural gasoline mix and stabilizedcondensate. The plant also has multiple tailgate interconnects for redeliveryof natural gas with KMTP, Houston Pipe Line Company (an affiliate of EnergyTransfer Partners, L.P.), Tennessee Gas Pipeline Company and Texas EasternTransmission. In addition, at the tailgate of the plant, we operate ourSheridan NGL Pipeline for transporting butane and natural gasoline mix, DowChemical operates a 6-inch diameter pipeline for transportation of ethaneand propane to Dow’s Freeport facility and TEPPCO operates an 8-inchdiameter crude oil and stabilized condensate pipeline that runs to refineriesin the 

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greater Houston area. OurHouston Central Processing Plant and related facilities are located on a 163-acretract of land, which we lease under three long-term lease 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 point specifications.Our ability to condition gas, rather than fully process it, provides us withsignificant benefits during periods when processing is not economic (when theprice 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 the price of natural gas is higher than NGLs; 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.

Our Houston Central Processing Plant has an inletcapacity of approximately 700,000 Mcf/d and had an average throughput of529,040 Mcf/d for the year ended December 31, 2004. This compares with anaverage daily throughput of 479,127 Mcf/d for the year ended December 31,2003. The average daily volume of ethane and propane delivered from the plantto the Dow NGL pipeline was 10,667 Bbls/d and 4,981 Bbls/d for 2004 and 2003,respectively. The average daily volume of butane and natural gasoline mixdelivered to the Sheridan NGL pipeline was 4,322 Bbls/d and 2,758 Bbls/d for2004 and 2003, respectively. The average daily volume of stabilized condensatedelivered from the plant to the TEPPCO crude oil pipeline was 379 Bbls/dand 241 Bbls/d for 2004 and 2003, respectively.

*SheridanNGL Pipeline.  *Our 104-mile, 6-inch diameterSheridan NGL pipeline originates at the tailgate of our Houston CentralProcessing Plant and currently delivers butane and natural gasoline mix intothe Enterprise Products Partners’ Seminole Pipeline for ultimate redelivery forfurther transportation and fractionation. We also have the ability to deliverthe ethane and propane through the Sheridan NGL line for redelivery toEnterprise’s Seminole Pipeline if the Dow pipeline were unavailable. The linehas a current capacity of 20,840 Bbls/d of NGLs, which we believe could beincreased with the installation of additional pump facilities. Averagethroughput volume on this system was 4,322 Bbls/d for the year ended December 31,2004 as compared with 2,758 Bbls/d for the year ended December 31,2003.

**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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Weprovide natural gas gathering, treating, conditioning, processing,fractionation, transportation, dehydration and compression services to ourcustomers. These processes 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.

·                     Lowerpressure gathering systems allow wells, which produce at progressively lowerfield pressures as they age, to remain connected to the gathering system andcontinue to produce for longer periods of time. As the well pressure declines,it becomes 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-pressuredownstream pipeline to be brought to market. Field compression is typicallyused to allow a gathering system to operate at a lower pressure or providesufficient discharge pressure to deliver gas into a higher-pressure downstreampipeline. If field compression is not installed, then the remaining natural gasin the ground will not be produced because it cannot overcome the highergathering system pressure. In contrast, if field compression is installed, thena well can continue delivering natural gas that otherwise would not beproduced.

·                     *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. Water in a naturalgas stream can also cause corrosion when combined with carbon dioxide orhydrogen sulfide in natural gas and condensed water in the pipeline can raiseinlet pipeline pressure and cause a greater pressure drop downstream. To avoidthese potential issues and to meet downstream pipeline and end-user gas qualitystandards, natural gas is dehydrated to remove the saturated 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 

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alleviate the potentialadverse effects of these contaminants, many pipelines regularly injectcorrosion inhibitors into the gas stream. Additionally, to render natural gaswith high carbon dioxide or hydrogen sulfide levels marketable, pipelines mayblend the gas with gas that contains low carbon dioxide or hydrogen sulfidelevels, or arrange for treatment to remove carbon dioxide and hydrogen sulfideto levels that meet pipeline quality standards.

·                     Theamine treating process involves a continuous circulation of a liquid chemicalcalled amine that physically contacts with the natural gas. Amine has achemical affinity for hydrogen sulfide and carbon dioxide that allows it toabsorb the impurities from the gas. After mixing, gas and amine are separatedand the impurities are removed from the amine by heating. The treating plantsare sized by the amine circulation capacity in terms of gallons per minute. Ourfacility has a circulation capacity of 700 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. We utilize propane refrigeration to moreaccurately and efficiently control the temperature used to condition thenatural gas stream. Conditioning of natural gas, rather than processing, is preferredduring 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 

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different NGL product isseparated and stored. This process is repeated until the NGLs have beenseparated into their components. Because the fractionation process uses largequantities of heat, fuel costs are a major component of the total cost offractionation.

·                     *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 aretransported to market by means of pipelines, pressurized barges, rail car andtank trucks. The method of transportation utilized depends on, among otherthings, the existing resources of the transporter, the locations of theproduction points and the delivery points, cost-efficiency and the quantity ofNGLs being transported. Pipelines are generally the most cost-efficient mode oftransportation when large, consistent volumes of NGLs are to be delivered.

**Risk Management**

As we purchase naturalgas, we establish a margin by selling natural gas for physical delivery tothird party users. Through these transactions, we seek to maintain a balancebetween our purchases and our sales or future delivery obligations. To mitigateprice basis risk, we also attempt to utilize the same reference index for theestablishment of price with respect to a sale transaction as utilized in therelated purchase transaction. Our practice is not to acquire and hold naturalgas future contracts or derivative products for the purpose of speculating onprice changes.

**Competition**

The natural gas gathering, transmission, treating,processing and marketing industries are highly competitive. We face strongcompetition in acquiring new natural gas supplies. Our competitors includemajor interstate and intrastate pipelines, and other natural gas gatherers thatgather, process and market natural gas. Competition for natural gas supplies isprimarily based on the reputation, efficiency, flexibility and reliability ofthe gatherer, the pricing arrangements offered by the gatherer, the location ofthe gatherer’s pipeline facilities and the ability of the gatherer to offer afull range of services, including processing, conditioning and treatingservices. We provide comprehensive services to natural gas producers, includingnatural gas gathering, transportation, compression, dehydration, treating, conditioningand processing. We believe our ability to furnish these services gives us anadvantage in competing for new supplies of natural gas because we can providethe services that producers, marketers and others require to connect theirnatural gas quickly and efficiently. In addition, using centralized treatingand processing facilities, we can in most cases attach producers that requirethese services more quickly and at a lower initial capital cost due in part tothe elimination of some field equipment and greater economies of scale at ourHouston Central Processing Plant. For natural gas that exceeds the maximumcarbon dioxide and NGL specifications for interconnecting pipelines anddownstream markets, we believe that we offer treating, conditioning and otherprocessing services on competitive terms. In addition, with respect to naturalgas customers attached to our pipeline systems, we are able to vary quantitiesof natural gas delivered to customers in response to market demands.

The primary difference between us and many of ourcompetitors is that we provide an integrated and responsive package ofmidstream services, while many of our competitors typically offer only a fewselect services. We believe that offering an integrated package of services,while remaining flexible in the types of contractual arrangements that we offerproducers, allows us to compete more effectively for new natural gas supplies.

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Many of our competitorshave capital resources and control supplies of natural gas greater than ours. Ourmajor competitors for natural gas supplies and markets in our four operatingregions include GulfTerra Energy Partners (a subsidiary of Enterprise ProductsPartners, L.P.), Lobo Pipeline Company (an affiliate of ConocoPhillips),KMTP, Duke Energy Field Services, Crosstex Energy, and Houston Pipe LineCompany (an affiliate of Energy Transfer Partners, L.P.). Our primarycompetitors for our processing business are GulfTerra Energy Partners (asubsidiary of Enterprise Products Partners, L.P.), ExxonMobil and DukeEnergy Field Services.

**Natural Gas Supply**

Our assets are located in four pipeline operatingregions in Texas that have experienced significant levels of drilling activity,providing us with opportunities to access newly developed natural gas supplies.We generally do not obtain independent evaluations of reserves dedicated to ourpipeline systems due to the cost of such evaluations and the lack of publiclyavailable producer reserve information. Accordingly, we do not have estimatesof total reserves dedicated to our systems or the anticipated life of suchproducing reserves.

During the year ended December 31, 2004, our topproducers by volume of natural gas were Noble Energy, Mesteña Operating,****Westport Oil and Gas Company (a subsidiary of Kerr-McGee),Dominion OK TX Exploration and Production and Gryphon Exploration**,** which collectively accounted for approximately 37% of thenatural gas delivered to our natural gas gathering and intrastate pipelinesystems 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 Item 7, “Management’s Discussion andAnalysis of Financial Condition and Results of Operation—Our Contracts—OurNatural Gas Supply and Transportation 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.

**Credit Risk andSignificant Customers**

We are diligent in attempting to ensure that weprovide credit to only credit-worthy customers. However, our purchase andresale of natural gas exposes us to significant credit risk, as the margin onany sale is generally a very small percentage of the total sale price. Therefore,a credit loss could be very large relative to our overall profitability.

During the year ended December 31,2004, we had three customers that collectively accounted for slightly more than60% of our consolidated revenue. During the year ended December 31, 2003,we had four customers that collectively accounted for almost 65% of ourconsolidated revenue. During the year ended December 31, 2002, we hadthree customers that collectively accounted for almost 63% of our consolidatedrevenue. Please read Note 12 to theConsolidated Financial Statements, “Customer Information” for additional information about our significantcustomers.

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**Kinder Morgan TexasPipeline**

KMTP is an intrastate natural gas pipeline system thatis principally located in the Texas Gulf Coast area. 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 Laredo-to-Katypipeline. By using KMTP as a transporter, we can transport natural gas frommany of our pipeline systems to our processing plant and downstream markets. Underour contractual 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. We refer to the natural gas delivered into KMTP’s pipelinefrom sources other than our gathering systems 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 upon180 days’ prior notice.

For the year ended December 31,2004, approximately 86% of the natural gas volumes processed or conditioned atour Houston Central Processing Plant were delivered to the plant through theKMTP Laredo-to-Katy pipeline while the remaining 14% were delivered directlyinto the plant from our gathering systems. Of the natural gas delivered intothe plant from the KMTP Laredo-to-Katy pipeline, approximately 23% wasdelivered from gathering systems controlled by us and 77% was delivered intoKMTP’s pipeline from other sources. Of the total volume of NGLs extracted atthe plant during this period, 45% was attributable to KMTP Gas, while 55% wasattributable to gas from gathering systems controlled by us, including ourgathering systems connected directly to the plant.

**Regulation**

*Regulationby the FERC of Interstate Natural Gas Pipelines.  *We donot own any interstate natural gas pipelines, so the Federal Energy RegulatoryCommission, or the FERC, does not directly regulate any of our operations. However,the FERC’s regulation influences certain aspects of our business and the marketfor our products. In general, the FERC has authority over natural gas companiesthat provide natural gas pipeline transportation services in interstatecommerce, and its authority to regulate 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.

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*Intrastate Pipeline 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. However, to the extent that our intrastate pipelines transport naturalgas in interstate commerce, the rates, terms and conditions of suchtransportation service are subject to the FERC jurisdiction under Section 311of the Natural Gas Policy Act, which regulates, among other things, theprovision of transportation services by an intrastate natural gas pipeline onbehalf of a local distribution company or an interstate natural gas pipeline.

Some of our operations are subject to the Texas GasUtility Regulatory Act, as implemented by the Railroad Commission of Texas, orthe TRRC. Generally the TRRC is vested with authority to ensure that ratescharged 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.

*Gathering Pipeline 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 that we believe wouldmeet the traditional tests the FERC has used to establish a pipeline’s statusas a gatherer not subject to the FERC jurisdiction. However, the distinctionbetween the FERC-regulated transmission services and federally unregulatedgathering services is the subject of regular litigation, so the classificationand regulation of some of our gathering facilities may be subject to changebased on future determinations by the FERC and the courts. State regulation ofgathering facilities generally includes various safety, environmental and, insome circumstances, nondiscriminatory take requirements and complaint-basedrate regulation.

We are subject to state ratable take and commonpurchaser statutes. The ratable take statutes generally require gatherers totake, without undue discrimination, natural gas production that may be tenderedto the gatherer for handling. Similarly, common purchaser statutes generallyrequire gatherers to purchase without undue discrimination as to source ofsupply or producer. These statutes are designed to prohibit discrimination infavor of one producer over another producer or one source of supply overanother source of supply. These statutes have the effect of restricting ourright as an owner of gathering facilities to decide with whom we contract topurchase or transport natural 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.

*Sales ofNatural Gas.  *The price at which we buy and sell naturalgas currently is not subject to federal regulation and, for the most part, isnot subject to state regulation. Our sales of natural gas are affected by theavailability, terms and cost of pipeline transportation. As noted above, theprice and terms of access to pipeline transportation are subject to extensivefederal and state regulation. The FERC is continually proposing andimplementing new rules and regulations affecting those segments of thenatural gas 

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industry, mostnotably interstate natural gas transmission companies that remain subject tothe FERC’s jurisdiction. These initiatives also may affect the intrastatetransportation of natural gas under certain circumstances. The stated purposeof many of these regulatory changes is to promote competition among the varioussectors of the natural gas industry, and these initiatives generally reflectmore light-handed regulation. We cannot predict the ultimate impact ofthese regulatory changes to our natural gas marketing operations, and we notethat some of the 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.

**EnvironmentalMatters**

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 activities in sensitive areas such as wetlands,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 limiting orprohibiting future operations. Certain environmental statutes impose strict,joint and several liability for costs required to clean up and restore siteswhere hazardous substances have been disposed or otherwise released. Moreover,it is not uncommon for neighboring landowners and other third parties to fileclaims for personal injury and property damage allegedly caused by the releaseof substances or other waste products into the environment.

The trend in environmental regulation is to place morerestrictions and limitations on activities that may affect the environment, andthus there can be no assurance as to the amount or timing of futureexpenditures for environmental compliance or remediation, and actual futureexpenditures may be different from the amounts we currently anticipate. We tryto anticipate future regulatory requirements that might be imposed and planaccordingly to remain in compliance with changing environmental laws andregulations and to minimize the costs of such compliance. We also activelyparticipate in industry groups that help formulate recommendations foraddressing existing or future regulations.

We do not believe that compliance with federal, stateor local environmental laws and regulations will have a material adverse effecton our business, financial position or results of operations. In addition, webelieve that the various environmental activities in which we are presentlyengaged are not expected to materially interrupt or diminish our operationalability to gather, compress, treat, process and transport natural gas. Wecannot assure you, however, that future events, such as changes in existinglaws, the promulgation of new laws, or the development or discovery of newfacts or conditions will not cause us to incur significant costs. The followingis a discussion of certain environmental and safety concerns that relate to themidstream natural gas industry.

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*Air Emissions.  *Ouroperations are subject to the federal Clean Air Act and comparable state lawsand regulations. These laws and regulations regulate emissions of airpollutants from various industrial sources, including our processing plant andcompressor 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 believe, however, that our operations will notbe materially adversely affected by such requirements, and the requirements arenot expected to be any more burdensome to us than to any other similarlysituated companies.

*Hazardous Waste.  *Ouroperations generate wastes, including some hazardous wastes, that are subjectto the federal Resource Conservation and Recovery Act, or RCRA, and comparablestate laws, which impose detailed requirements for the handling, storage,treatment and disposal of hazardous and solid waste. RCRA currently exemptsmany natural gas gathering and field processing wastes from classification ashazardous waste. Specifically, RCRA excludes from the definition of hazardouswaste produced waters and other wastes associated with the exploration,development, or production of crude oil and natural gas. However, these oil andgas exploration and production wastes may still be regulated under state law orthe less stringent solid waste requirements of RCRA. Moreover, ordinary industrialwastes such as paint wastes, waste solvents, laboratory wastes, and wastecompressor oils may be regulated as hazardous waste. The transportation ofnatural gas in pipelines may also generate some hazardous wastes that aresubject to RCRA or comparable state law requirements.

*Site Remediation.  *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 originalconduct, 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 somecases, third parties to take actions in response to threats to the publichealth or the environment and to seek to recover from the responsible classesof persons the costs they incur. Under CERCLA, we could be subject to joint andseveral liability for the costs of cleaning up and restoring sites wherehazardous substances have been released, for damages to natural resources, andfor the costs of certain health studies.

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. Althoughwe used operating and disposal practices that were standard in the industry atthe time, hydrocarbons or wastes may have been disposed of or released on orunder the properties owned or leased by us or on or under other locations wheresuch wastes have been taken for disposal. In addition, some of these propertieshave been operated by third parties or by previous owners whose treatment anddisposal or release of hydrocarbons or wastes was not under our control. Theseproperties and the substances disposed or released on them may be subject toCERCLA, RCRA and analogous state laws. Under such laws, we could be required toremove previously disposed wastes (including waste disposed of by prior ownersor operators), remediate contaminated property (including groundwatercontamination, whether 

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from prior owners oroperators or other historic activities or spills), or perform remedial pluggingor pit closure operations to prevent future contamination.

*Water Discharges.  *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 waters of the United States.The discharge of pollutants, including discharges resulting from a spill orleak incident, is prohibited unless authorized by a permit or other agencyapproval. The Clean Water Act and regulations implemented thereunder alsoprohibit discharges of dredged and fill material in wetlands and other watersof the United 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.

*Pipeline Safety.  *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 applicable 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 that, at this time,cannot reasonably be quantified.

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. Similarrules are already in place for operators of hazardous liquid pipelines. TheTexas Railroad Commission, or TRRC, has adopted similar regulations applicableto intrastate gathering and transmission lines. Compliance with these rules hasnot had a material adverse effect on our operations but there is no assurancethat this trend will continue in the future.

*EmployeeHealth and Safety.  *We are subject to the requirementsof the Occupational Safety and Health Act, referred to as OSHA, and comparablestate laws that regulate the protection of the health and safety of workers. Inaddition, the OSHA hazard communication standard requires that information bemaintained about hazardous materials used or produced in our operations andthat this information be provided to employees, state and local governmentauthorities and citizens.

**Office Facilities**

We occupy approximately15,500 square feet of space at our executive offices in Houston, Texas under alease expiring on March 31, 2010. At the expiration of the primary term,we have an option to renew this lease for an additional five years at the thenprevailing market rates. We also lease office facilities in Alice andHebbronville, Texas, which consist of approximately 1,863 square feet and500 square feet of office space, respectively. We own office facilities inConroe, Sheridan and Lamar, Texas, which consist of approximately 3,000 squarefeet, 10,000 square feet and 1,200 square feet, respectively. Certain ofour owned office facilities are located on land leased by us or on land subjectto a permanent easement. While we may require additional office space as ourbusiness expands, we believe that our existing facilities are 

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adequateto meet our needs for the immediate future and that additional facilities willbe available on commercially reasonable terms as needed.

**Employees**

As of December 31,2004, we had no direct employees other than certain Delaware-basedofficers. To carry out our operations, one of our affiliates, CopanoOperations, employed 85 full-time employees on our behalf as of December 31,2004. Effective January 1, 2005 and pursuant to our general andadministrative services agreement with Copano Operations, Copano Operationstransferred responsibility to us for a significant portion of the services thatit had previously provided to us. As a result, as of March 15, 2005, wehad 74 full time employees and Copano Operations continued to employ 12full-time employees on our behalf. None of our employees are covered bycollective bargaining agreements. We consider our relations with theseemployees, with Copano Operations and with those Copano Operations’ employeesproviding services to us to be good. In exchange for providing general and administrativeservices to us, including employing certain personnel on our behalf, we arerequired to reimburse Copano Operations for its costs and expenses. To theextent these employees will be dedicated to provide services on our behalf, werefer 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.

**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 all of 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, 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 legal or governmentalproceedings against us, or contemplated to be brought against us, under thevarious environmental protection statutes to which we are subject.

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

No matters were submitted to a vote of securityholders during the fourth quarter of 2004.

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**PART II**

**Item 5.**                        Market forRegistrant’s Common Equity, Related Unitholder Matters and Issuer Purchases ofEquity Securities

Our common units representing limited liabilitycompany interests in us are listed on The NASDAQ National Market, or NASDAQ,under the symbol “CPNO.” Our common units began trading on November 9,2004, following our initial public offering. Our initial public offering pricewas $20.00 per common unit. On March 28, 2005, the market price for ourcommon units was $29.50 per unit. There were approximately 3,100 commonunitholders, of which there were approximately 20 common unitholders of record.Additionally, there were 12 unitholders of record of our subordinated units. Thereis no established public trading market for our subordinated units.

Thefollowing table shows the high and low closing sales prices per common unit, asreported by NASDAQ, for the periods indicated:
| ** **                     | ** ** | ** **           | ** ** | **Cash**          | ** ** |
|--------------------------------|------------|----------------------|------------|-------------------|------------|
| ** **                     | ** ** | **Common Unit** | ** ** | **Distribution**  | ** ** |
| ** **                     | ** ** | **Price Range** | ** ** | **Paid Per** | ** ** |
| ** **                     | ** ** | **High**             | ** ** | **Low**           | ** ** | **Unit** | ** ** |
| **2004:**                      |       |                 |       |              |       |   |   |   |   |
| Quarter Ended December 31 |       | $                    | 28.50      |              | $          | 23.25 |   |   | $ | 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, the minimumquarterly distribution of $0.40 per unit (or $1.60 per year), to our common andsubordinated unitholders of record on the applicable record date. During thesubordination period (as described below), the common units will have the rightto receive distributions of available cash from operating surplus in an amountequal to the minimum quarterly distribution of $0.40 per quarter, plus anyarrearages in the payment of the minimum quarterly distribution on the commonunits from prior quarters, before any distributions of available cash fromoperating surplus may be made on the subordinated units. Our available cashconsists generally of all cash on hand at the end of the fiscal quarter, lessreserves that our board determines are necessary to a) provide for the properconduct of our business; b) comply with applicable law, any of our debtinstruments, or other agreements; or (c) provide funds for distributionsto our unitholders for any one or more of the next four quarters; plus all cashon hand for the quarter resulting from eligible working capital borrowings madeafter the end of the quarter on the date of determination of available cash. Operatingsurplus generally consists of cash on hand at closing, cash generated fromoperations after deducting related expenditures and other items, plus eligibleworking capital borrowings after the end of the quarter, plus $12.0 million, asadjusted for reserves. We have not established a credit facility that providesfor the type of working capital borrowings that would be eligible, pursuant toour limited liability company agreement, to be considered available cash oroperating surplus distributable to our unitholders.

Our board has broad discretion to establish cashreserves that it determines are necessary or appropriate to properly conductour business. These can include cash reserves for future capital andmaintenance expenditures, reserves to stabilize distributions of cash to theunitholders, reserves to reduce debt, or, as necessary, reserves to comply withthe terms of any of our agreements or obligations.

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Theamount of available cash from operating surplus needed to pay the minimumquarterly distribution to our common and subordinated unitholders is as follows(in thousands):
| ** **      | ** ** | **One Quarter** | ** ** | **Four Quarters** | ** ** |
|-----------------|------------|----------------------|------------|------------------------|------------|
| Common units(1) |       |                 | $          | 2,815                  |       |   |   | $ | 11,261 |   |   |
| Subordinated    |       |                 | 1,408      |                   |       |   | 5,631 |   |   |
| Total           |       |                 | $          | 4,223                  |       |   |   | $ | 16,892 |   |   |

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(1)          Excludes distributionsattributable to restricted units as distributions made on restricted unitsissued to date are subject to the same vesting provisions as the restrictedunits. On December 13, 2004, we  awarded 3,000 restricted common units to eachof our six independent directors, for a total of 18,000 units. Each restrictedunit granted to our independent board members vests in equal one-third annualinstallments commencing on the first anniversary of the grant date or upon achange of control, death, disability or, in certain circumstances, retirement. Annualdistributions related to these restricted units are less than $30,000.

During the subordination period, the common units willhave the right to receive distributions of available cash from operatingsurplus in an amount equal to the minimum quarterly distribution of $0.40 perquarter, plus any arrearages in the payment of the minimum quarterlydistribution on the common units from prior quarters, before any distributionsof available cash from operating surplus may be made on the subordinated units.The purpose of the subordinated units is to increase the likelihood that duringthe subordination period there will be available cash to be distributed on thecommon 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 periodsimmediately preceding that date equaled or exceeded the minimum quarterlydistribution;

·       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 the subordination period, allsubordinated units will convert into common units on a one-for-one basis andwill then participate, pro rata, with the other common units in distributionsof available cash, and the common units will no longer be entitled toarrearages.

Please read theinformation incorporated by reference under Item 12, “Security Ownership ofCertain Beneficial Owners and Management” of this Annual Report, regardingsecurities authorized for issuance under our equity compensation plans whichinformation is incorporated by reference into this 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 First Boston Private Equity (“CSFB”)and 375,000 common units from affiliates of EnCap Investments L.P. (“EnCap”). Theredemption price for the common units was $18.60 per common unit, which was theinitial public offering price to our public common unitholders lessunderwriting discounts. There were no other repurchases of our equitysecurities during the fourth quarter of 2004.

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**RecentSales of Unregistered Securities**

In connection withour formation and through a series of transactions occurring between August 14,2001 and November 27, 2001, we issued to Copano Partners, L.P., an affiliateof John R. Eckel, Jr., our Chairman and Chief Executive Officer, 1,030,000common units (1,299,020 as restated) and 620,000 junior units for assets havinga net book value of approximately $4 million. Additionally, through a series oftransactions occurring between August 14, 2001 and November 27, 2001,we issued:

·       1,875,000warrants to purchase common units and 300,000 redeemable preferred units toaffiliates of CSFB for $30 million; and

·       1,875,000warrants to purchase common units and 300,000 redeemable preferred units toaffiliates of EnCap for $30 million.

Each of these transactionswas exempt from registration under Section 4(2) of the Securities Actas the transaction did not involve a public offering. Between November 1,2001 and our initial public offering, we issued 88,982 additional redeemablepreferred units to CSFB and 88,892 additional redeemable preferred units toaffiliates of EnCap in lieu of quarterly cash distributions.

Effective January 2002, we designated 212,000nonvoting special units of our company, 154,000 of which were designated ascommon special units and 58,000 of which were designated as junior specialunits. Of the designated amounts, 54,000 common special units and 18,000 juniorspecial units were sold, effective January 2002, to one of our executiveofficers and, effective April 2003, an additional 100,000 common specialunits and 40,000 junior special units were sold to another executive officer ofour company. The acquisition price for the common special units and the juniorspecial units was $1.00 per unit and $0.50 per unit, respectively. Each ofthese transactions was exempt from registration under Section 4(2) ofthe Securities Act as the transaction did not involve a public offering.

On November 15, 2004, in connection with ourinitial public offering, all of our equity securities outstanding prior to ourinitial public offering (including the equity securities referred to above)were converted into our common units and subordinated units, and allocatedamong our pre-offering unitholders pursuant to a pre-arranged formula.

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

**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 consolidatedfinancial data for the years ended December 31, 2004, 2003, 2002 and 2001are derived from the audited consolidated financial statements of CopanoEnergy, L.L.C. The selected historical consolidated financial data for the yearended December 31, 2000 are derived from the unaudited consolidatedfinancial statements of our predecessor entities.

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 segment gross margin asrevenue less 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 27 of this Annual Report.

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Maintenance capital expenditures represent capitalexpenditures made to replace partially or fully depreciated assets to maintainthe existing operating capacity of our assets and to extend their useful lives,or other capital expenditures that are incurred in maintaining existing systemvolumes and related cash flows. 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, such as our recent acquisition of the Karnes CountyGathering System, are 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. We treat costs forrepairs and minor renewals to maintain facilities in operating condition andthat do not extend the useful life of existing assets as operations andmaintenance expenses as we incur them.

We derived the informationin the following table from, and that information should be read together withand is qualified in its entirety by reference to, our historical consolidatedfinancial statements and the accompanying notes included in Item 8 of thisAnnual Report. The selected financial information should be read together withItem 7, “Management’s Discussion and Analysis of Financial Condition andResults of Operation.”

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| ** **                                               | ** ** | **Year Ended December 31,**                        | ** ** |
|----------------------------------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                                               | ** ** | **2004**                                                          | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| ** **                                               | ** ** | **(In thousands, except per unit data)** | ** ** |
| **Summary of Operations Data:**                          |       |                                                              |       |   |   |   |   |   |   |   |   |
| Revenues                                                 |       | $                                                                 | 437,656    |   | $ | 384,571 |   | $ | 224,896 |   | $ | 160,369 |   | $ | 107,381 |   |
| Cost of sales                                            |       | 386,155                                                           |       | 353,376 |   | 199,525 |   | 143,381 |   | 96,028 |   |
| Operations and  maintenance expenses                     |       | 12,486                                                            |       | 10,854 |   | 9,562 |   | 4,960 |   | 1,780 |   |
| Depreciation and  amortization                           |       | 7,287                                                             |       | 6,091 |   | 5,539 |   | 3,326 |   | 2,191 |   |
| General and  administrative expenses                     |       | 9,217                                                             |       | 5,849 |   | 4,177 |   | 2,171 |   | 1,460 |   |
| Taxes other than income                                  |       | 770                                                               |       | 926 |   | 891 |   | 435 |   | 331 |   |
| Equity in (earnings) loss  from unconsolidated affiliate |       | (419                                                              | )          | 127 |   | 584 |   | — |   | — |   |
| Operating income                                         |       | 22,160                                                            |       | 7,348 |   | 4,618 |   | 6,096 |   | 5,591 |   |
| Interest and other  financing costs                      |       | (23,160                                                           | )          | (12,108 | ) | (6,360 | ) | (2,227 | ) | (299 | ) |
| Interest income and other                                |       | 85                                                                |       | 43 |   | 101 |   | 183 |   | 150 |   |
| Net (loss) income                                        |       | $                                                                 | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) | $ | 4,052 |   | $ | 5,442 |   |
| Basic and diluted net  (loss) income per unit:(1)        |       | $                                                                 | (0.35      | ) | $ | (6.21 | ) | $ | (6.77 | ) | $ | 2.25 |   |   |   |
| Cash distributions per  common unit(1)                   |       | $                                                                 | 1.01       |   | $ | — |   | $ | 0.22 |   | $ | 0.31 |   |   |   |
| **Balance  Sheet Data (at period end):**                 |       |                                                              |       |   |   |   |   |   |   |   |   |
| Total assets                                             |       | $                                                                 | 178,399    |   | $ | 161,709 |   | $ | 159,521 |   | $ | 152,258 |   | $ | 71,530 |   |
| Property, plant and  equipment, net                      |       | 119,683                                                           |       | 117,032 |   | 116,888 |   | 109,158 |   | 45,427 |   |
| Payables to affiliates                                   |       | 127                                                               |       | 1,371 |   | 932 |   | 1,090 |   | 623 |   |
| Long-term debt                                           |       | 57,000                                                            |       | 57,898 |   | 68,740 |   | 65,354 |   | 3,350 |   |
| Redeemable preferred  units                              |       | —                                                            |       | 60,982 |   | 53,559 |   | 48,327 |   | — |   |
| Members’ capital                                    |       | 82,356                                                            |       | (662 | ) | 6,577 |   | 16,157 |   | 49,131 |   |
| **Cash  Flow Data:**                                     |       |                                                              |       |   |   |   |   |   |   |   |   |
| Net cash flow provided by  (used in):                    |       |                                                              |       |   |   |   |   |   |   |   |   |
| Operating  activities                                    |       | $                                                                 | 17,697     |   | $ | 15,296 |   | $ | 8,865 |   | $ | 13,107 |   | $ | 4,788 |   |
| Investing  activities                                    |       | (8,920                                                            | )          | (6,192 | ) | (16,817 | ) | (93,335 | ) | (3,318 | ) |
| Financing  activities                                    |       | (6,369                                                            | )          | (9,633 | ) | (2,591 | ) | 93,938 |   | (430 | ) |
| **Other  Financial Data:**                               |       |                                                              |       |   |   |   |   |   |   |   |   |
| Pipeline segment gross  margin(2)                        |       | $                                                                 | 30,076     |   | $ | 27,551 |   | $ | 18,772 |   | $ | 11,529 |   | $ | 11,353 |   |
| Processing segment gross  margin(3)                      |       | 21,425                                                            |       | 3,644 |   | 6,599 |   | 5,459 |   | — |   |
| Total gross margin(2)                                    |       | $                                                                 | 51,501     |   | $ | 31,195 |   | $ | 25,371 |   | $ | 16,988 |   | $ | 11,353 |   |
| EBITDA(2)                                                |       | $                                                                 | 29,532     |   | $ | 13,482 |   | $ | 10,258 |   | $ | 9,605 |   | $ | 7,932 |   |
| Maintenance capital  expenditures                        |       | $                                                                 | 1,790      |   | $ | 2,281 |   | $ | 3,781 |   | $ | 1,175 |   | $ | 668 |   |
| Expansion capital  expenditures                          |       | 7,130                                                             |       | 3,911 |   | 9,323 |   | 56,746 |   | 2,863 |   |
| Total capital  expenditures                              |       | $                                                                 | 8,920      |   | $ | 6,192 |   | $ | 13,104 |   | $ | 57,921 |   | $ | 3,531 |   |
| **Operating  Data:**                                     |       |                                                              |       |   |   |   |   |   |   |   |   |
| Pipeline  throughput(4) (Mcf/d)                     |       | 220,970                                                           |       | 238,800 |   | 247,613 |   | 228,657 |   | 87,907 |   |
| Processing plant(3)                                      |       |                                                              |       |   |   |   |   |   |   |   |   |
| Inlet volumes  (Mcf/d)                                   |       | 529,040                                                           |       | 479,127 |   | 571,217 |   | 614,521 |   | — |   |
| NGLs produced  (Bbls/d)                                  |       | 15,373                                                            |       | 7,280 |   | 12,656 |   | 15,227 |   | — |   |

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(1)    Net(loss) income per unit and cash distributions per common unit are not providedfor the year ended December 31, 2000 as this financial informationrepresents financial results of predecessor entities that have been combinedfor comparative purposes. Net (loss) income per unit is based on the weightedaverage equivalent units outstanding during the periods presented. For periodsprior to our initial public offering, equivalent units were calculated usingthe weighted average of pre-initial public offering common units and commonspecial units adjusted by a conversion or exchange factor. The computation ofdiluted units outstanding for all periods presented excludes incremental unitsrelated to warrants previously held by preferred unitholders and employee unitoptions because these equity securities had an anti-dilutive effect as a resultof losses reported by us for these periods. After our initial public offeringin November 2004, total units outstanding as of December 31, 2004were 10,575,378 units, comprised of 7,056,252 common units and 3,519,126subordinated units. Cash distributions for 2002 and 2001 have been restated toreflect the conversion discussed previously and the cash distributions for 2004relate to the distributions paid to the pre-offering unitholders prior to ourinitial public offering and are based on equivalent units.

(2)    Under the equity method of accounting, these amountsinclude our equity in the earnings (loss) of Webb/Duval Gatherers, which we owna 62.5% partnership interest, in the amounts of $419, $(127) and $(584) for theyears ended December 31, 2004, 2003 and 2002, respectively.

(3)    We initiated processing upon acquisition of our HoustonCentral Processing Plant in August 2001.

(4)    Excludes volumes associated with our interest inWebb/Duval Gatherers, which we acquired in November 2001 and February 2002.With respect to assets acquired mid-year, our operating data represents dailyvolumes for the portion of the year we owned the asset.

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The following tablepresents a reconciliation of the non-GAAP financial measures of (1) totalgross margin (which consists of the sum of individual segment gross margins) tooperating income and (2) EBITDA to the GAAP financial measures of net (loss)income and cash flows from operating activities on a historical basis for eachof the periods indicated.
| ** **                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                         | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| Reconciliation of  total gross margin to operating income:         |       |                                       |       |   |   |   |   |   |   |   |   |
| Operating income                                                   |       | $                                          | 22,160     |   | $ | 7,348 |   | $ | 4,618 |   | $ | 6,096 |   | $ | 5,591 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Operations and maintenance expenses                                |       | 12,486                                     |       | 10,854 |   | 9,562 |   | 4,960 |   | 1,780 |   |
| Depreciation and amortization                                      |       | 7,287                                      |       | 6,091 |   | 5,539 |   | 3,326 |   | 2,191 |   |
| General and administrative expenses                                |       | 9,217                                      |       | 5,849 |   | 4,177 |   | 2,171 |   | 1,460 |   |
| Taxes other than income                                            |       | 770                                        |       | 926 |   | 891 |   | 435 |   | 331 |   |
| Equity in (earnings) loss of unconsolidated  affiliate        |       | (419                                       | )          | 127 |   | 584 |   | — |   | — |   |
| Total gross margin                                                 |       | $                                          | 51,501     |   | $ | 31,195 |   | $ | 25,371 |   | $ | 16,988 |   | $ | 11,353 |   |
| Reconciliation  of EBITDA to net (loss) income:                    |       |                                       |       |   |   |   |   |   |   |   |   |
| Net (loss) income                                                  |       | $                                          | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) | $ | 4,052 |   | $ | 5,442 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Depreciation and amortization                                      |       | 7,287                                      |       | 6,091 |   | 5,539 |   | 3,326 |   | 2,191 |   |
| Interest expense                                                   |       | 23,160                                     |       | 12,108 |   | 6,360 |   | 2,227 |   | 299 |   |
| EBITDA                                                             |       | $                                          | 29,532     |   | $ | 13,482 |   | $ | 10,258 |   | $ | 9,605 |   | $ | 7,932 |   |
| Reconciliation  of EBITDA to cash flows from operating activities: |       |                                       |       |   |   |   |   |   |   |   |   |
| Cash flow from operating activities                                |       | $                                          | 17,697     |   | $ | 15,296 |   | $ | 8,865 |   | $ | 13,107 |   | $ | 4,788 |   |
| Add:                                                               |       |                                       |       |   |   |   |   |   |   |   |   |
| Cash paid for interest and other financing costs                   |       | 4,029                                      |       | 3,033 |   | 2,543 |   | 946 |   | 211 |   |
| Equity in earnings (loss) of unconsolidated  affiliate        |       | 419                                        |       | (127 | ) | (584 | ) | — |   | — |   |
| Increase (decrease) in working capital                             |       | 7,387                                      |       | (4,720 | ) | (566 | ) | (4,448 | ) | 2,933 |   |
| EBITDA                                                             |       | $                                          | 29,532     |   | $ | 13,482 |   | $ | 10,258 |   | $ | 9,605 |   | $ | 7,932 |   |

 

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**Item 7.   Management’s Discussion and Analysis ofFinancial 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 this AnnualReport. In addition, the reader should review “Forward-Looking Statements” and “RiskFactors” contained in this Item 7 of this Annual Report for informationregarding forward-looking statements made in this discussion and certain risksinherent in our business. Other risks involved in our business are discussedunder Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”References in this Item 7 to “Copano Energy, L.L.C.,” “we,” “our,” “us,” orlike terms refer to Copano Energy, L.L.C. and its consolidated subsidiaries.*

**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 a priceof $20.00 per unit, inclusive of 750,000 common units which were issued as aresult of the underwriters’ exercise of their over-allotment option. Netproceeds from the sale of the units totaled $106.95 million.

We own networks of natural gas gathering andintrastate pipelines in the Texas Gulf Coast region. Our natural gas processingplant is the second largest in the Texas Gulf Coast region and the thirdlargest in Texas in terms of throughput capacity. The plant is locatedapproximately 100 miles southwest of Houston, Texas.

We manage ourbusiness and analyze and report our results of operations on a segment basis. Ouroperations are divided into two business segments, Copano Pipelines and CopanoProcessing.

·       *Copano Pipelines* is engaged in thegathering and intrastate transmission of natural gas in areas we refer to asthe South Texas, Coastal Waters, Central Gulf Coast and Upper Gulf Coastregions. Within this segment, we also provide certain related servicesincluding compression, dehydration and marketing of natural gas. For the yearsended December 31, 2004 and 2003, this segment generated approximately 58%and 88%, respectively, of our total gross margin.

·       *Copano Processing* is engaged in naturalgas processing, conditioning and treating and NGL fractionation andtransportation through our Houston Central Processing Plant and Sheridan NGLPipeline. For the years ended December 31, 2004 and 2003, this segmentgenerated approximately 42% and 12%, respectively, of our total gross margin.

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 gas processed,conditioned or treated at our Houston Central Processing Plant, (3) thelevel and relationship of natural gas and NGL prices and (4) our currentcontract portfolio. Because our profitability is a function of the differencebetween the revenues we receive from our operations, including revenues fromthe products we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio and the pricingenvironment for natural gas and NGLs will dictate increases or decreases in ourprofitability. For a discussion of the types of contracts we utilize andmanagement’s analysis of our recent results of operations, please read “—OurContracts” and “—Our Results of Operation.” Our profitability is also dependentupon prices and market demand for natural gas and NGLs, which fluctuate withchanges in market and economic conditions and other factors.

The margins we realizefrom a significant portion of the natural gas that we gather or transportthrough our pipeline systems decrease in periods of low natural gas pricesbecause our gross margins on 

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suchnatural gas volumes are based on a percentage of the index price. Theprofitability of our processing operations is dependent upon the relationshipbetween natural gas and NGL prices. When natural gas prices are low relative toNGL prices it is more profitable for us to process natural gas than tocondition it. Conversely, when natural gas prices are high relative to NGLprices, processing is less profitable or unprofitable. During such periods, wehave the flexibility to condition natural gas rather than fully process it. Conditioningnatural gas, however, is less profitable than processing during periods whenthe value of recovered NGLs exceeds the value of natural gas required for plantfuel and to replace the reduced British thermal units, or Btus, that result fromprocessing the natural gas.

*How We Evaluate OurOperations*

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; and (5) EBITDA.

*Throughput Volumes.  *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 the Houston Central Processing Plant is significantly influencedby both the volume of natural gas coming into the plant and the NGL content ofthe natural gas. In addition, we monitor fuel consumption because it has asignificant impact on the gross margin realized from our processing orconditioning operations. Although we monitor fuel costs associated with ourpipeline operations, these costs are frequently passed on to our producers.

*Segment Gross Margin.  *Wedefine segment gross margin as our revenue minus cost of sales. Cost of salesincludes 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, which is described in more detail below. Withrespect to our Copano Pipelines segment, our management analyzes segment grossmargin per unit of volumes gathered or transported. With respect to our CopanoProcessing segment, our management also analyzes segment gross margin per unitof natural gas processed or conditioned and the segment gross margin per unitof NGLs recovered. Our segment gross margin is reviewed monthly for consistencyand trend analysis.

In order to isolate and consistently track changes incommodity price relationships and their impact on our 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 our current operating commodity price environment and we usethis calculation to track commodity price relationships. Our results ofoperations may not necessarily correlate to the changes in our standardizedprocessing margin because of the impact of factors other than commodity pricessuch as volumes, changes in NGL composition, recovery rates and variablecontract terms. Our standardized processing margins averaged $0.193 per gallonduring the fourth quarter of 2004 compared to $0.077 per gallon during thefourth quarter of 2003. Our standardized processing margins 

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averaged $0.105 per gallonduring the year ended December 31, 2004 compared to $0.002 per gallonduring the year ended December 31, 2003. The average standardizedprocessing margin for the period from 1989 through December 31, 2004 is$0.091 per gallon.

*Operations and Maintenance Expenses.  *Operationsand maintenance expenses are costs associated with the operations of a specificasset. Direct labor, insurance, ad valorem taxes, repair and maintenance,utilities and contract services comprise the most significant portion ofoperations and maintenance expenses. These expenses remain relatively stableacross broad volume ranges and fluctuate slightly depending on the activitiesperformed during a specific period. A portion of our operations and maintenanceexpenses are incurred through Copano Operations, an affiliate of our company. Underthe terms of our arrangement with Copano Operations, we will reimburse it, atcost, for the operations and maintenance expenses it incurs on our behalf. EffectiveJanuary 1, 2005 and pursuant to our general and administrative servicesagreement with Copano Operations, Copano Operations transferred responsibilityto us for a significant portion of the services, including certain operatingand maintenance services, that it had previously provided to us.

*General and Administrative Expenses.  *Ourgeneral and administrative expenses include the cost of employee and officercompensation and related benefits, office lease and expenses, professionalfees, information technology expenses, as well as other expenses not directlyassociated with our field operations. Substantially all of our general andadministrative expenses were incurred through Copano Operations, an affiliateof our company, through December 31, 2004. Effective January 1, 2005and pursuant to our general and administrative services agreement with CopanoOperations, Copano Operations transferred responsibility to us for asignificant portion of the services, including certain general andadministrative services, that it had previously provided to us.

Pursuantto our limited liability company agreement, our pre-offering investors haveagreed to reimburse us for our general and administrative expenses in excess ofstated levels (subject to certain limitations) for a period of three yearsbeginning on 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 Limitation** | ** ** |
|----------|------------|------------|------------|-----------------------------------------------------------------------|------------|
| 1        |       |       | $          | 1.50 million per quarter                                         |       |   |
| 2        |       |       | $          | 1.65 million per quarter                                         |       |   |
| 3        |       |       | $          | 1.80 million  per quarter                                        |       |   |

 

During this three-yearperiod, the quarterly limitation on general and administrative expenses will beincreased by 10% of the amount by which EBITDA for any quarter exceeds$5.4 million. Additionally, the cap may be extended beyond its initialthree-year term at the same or a higher level by the affirmative vote of atleast 95% of the common and subordinated units held by the existing investorsor their transferees, voting together as a single class. We can provide noassurance as to any such extension, as such determination will be made in thesole discretion of our pre-offering investors. This cap on general andadministrative expenses excludes non-cash expenses as well as expenses wemay incur in connection with potential acquisitions and capital improvements.

Immediately prior to completion of the initial publicoffering, we distributed to our pre-offering investors $4 million. Ourpre-offering investors deposited these funds in escrow accounts to be used forthe purpose of satisfying their respective general and administrative expensereimbursement obligation. If the escrow accounts are exhausted, any furtherreimbursement obligation will be limited to the amount of the distributionsattributable to our common and subordinated units owned by the pre-offeringinvestors immediately prior to our initial public offering. We believe that theescrowed funds, together with the 

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anticipated distributionson these common units and subordinated units, will provide us with additionalassurance that our pre-offering investors will be able to satisfy theirrespective reimbursement obligations.

*EBITDA.  *Wedefine EBITDA as net income (loss) plus interest expense, provision for incometaxes and depreciation and amortization expense. EBITDA is used as asupplemental financial measure by our management and by external users of ourfinancial statements such as investors, commercial banks, research analysts andothers, 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 financialmeasurement that, with certain negotiated adjustments, is reported to ourlenders and is used to compute our financial covenants under our creditfacilities. EBITDA should not be considered an alternative to net income,operating income, cash flows from operating activities or any other measure offinancial performance presented in accordance with GAAP.

*How We Manage OurOperations*

Our management team uses a variety of tools to manageour business. These tools include: (1) our processing and conditioningeconomic model; (2) flow and transaction monitoring systems; (3) produceractivity evaluation and reporting; and (4) imbalance monitoring and control.

*Our Processing and ConditioningEconomic Model.  *We utilize a processing andconditioning economic model to determine whether we should process or conditionnatural gas at our Houston Central Processing Plant. This model allowsmanagement to analyze whether current natural gas and NGL pricing supportsoperating our Houston Central Processing Plant at full processing mode orwhether it is economically more advantageous to operate the plant in aconditioning mode. For a detailed discussion of our processing and conditioningcapabilities, please read Item 1, “Business—Copano Processing.”

*Flow and Transaction MonitoringSystems.  *We utilize proprietary systems that trackcommercial activity on each of our pipelines and monitor the flow of naturalgas on our pipelines. For example, we designed and implemented software thattracks each of our natural gas transactions, which allows us to continuouslytrack volumes, pricing, imbalances and estimated revenues from our pipelineassets. Additionally, we designed and installed a Supervisory Control and DataAcquisition (SCADA) system, which assists management in monitoring andoperating our pipeline systems. The SCADA system allows us to monitor ourassets at remote locations and respond to changes in pipeline operatingconditions from our corporate office.

*Producer Activity Evaluation andReporting.  *We monitor the producer drilling andcompletion activity in our areas of operation to identify anticipated changesin production and potential new well attachment opportunities. The continuedattachment of natural gas production to our pipeline systems is critical to ourbusiness and directly impacts our financial performance. Using a third-partyelectronic reporting system, we receive daily reports of new drilling permitsand completion reports filed with the state regulatory agency that governsthese activities. Additionally, our field personnel report the locations of newwells in their respective areas and anticipated changes in production volumesto supply representatives and operating personnel at our corporate office. Theseprocesses enhance our awareness of new well activity in 

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our operating areas andallow us to be responsive to producers in connecting new volumes of natural gasto our pipelines.

*ImbalanceMonitoring and Control.  *We continually monitor volumesreceived and volumes delivered on behalf of third parties to ensure we remainwithin acceptable imbalance limits during the calendar month. We seek to reduceimbalances because of the inherent commodity price risk that results whenreceipts and deliveries of natural gas are not balanced concurrently. We haveimplemented “cash-out” provisions in many of our transportation agreements toreduce this commodity price risk. Cash-out provisions require that anyimbalance that exists between a third party and us at the end of a calendarmonth is settled in cash based upon a pre-determined pricing formula. Thisprovision ensures that imbalances under such contracts are not carried forwardfrom month-to-month and revalued at higher or lower prices.

**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 producer preferences,our expansion in regions where some types of contracts are more common andother market factors.

*Our Natural GasSupply and Transportation Contracts*

Our pipeline segment purchases natural gas fortransportation and resale and also transports and provides other services fornatural gas that it does not purchase on a fee-for-service basis. For the yearended December 31, 2004, we purchased 68.2% of the natural gas volumesdelivered to our pipelines and transported 31.8% on a fee-for-service basis. Thesevolumes exclude volumes associated with Webb/Duval Gatherers, substantially allof which are transported on a fee-for-service basis.

*Natural Gas 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, 2004,volumes related to discount-to-index purchase arrangements accounted for 95.3%of total 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 ourportfolio for the month. Transactions under these arrangements are executed tosupport intra-month changes in operating conditions, including customerrequirements, and not for purposes of speculation. For the year ended December 31,2004, volumes related to such fixed-price arrangements accounted for 4.8%of total purchased volumes.

*Fee-For-Service.  *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 

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arrangements would bereduced. For the year ended December 31, 2004, volumes related to fixed-feearrangements accounted for 63.9% of total natural gas volumes that we transporton behalf of third-party shippers.

We also derive sometransportation fee income based upon percentage-of-index fee arrangements. Underthis type of arrangement, the fee we receive for gathering or transporting thenatural gas is based upon a percentage of an index price. The fee we realizeunder this type of arrangement decreases in periods of low natural gas pricesand increases during periods of high natural gas prices. For the year ended December 31,2004, volumes related to percentage-of-index fee arrangements accounted for2.8% of total transported volumes. For the year ended December 31, 2004,volumes related to a combination of fixed-fee and percentage-of-indexfee arrangements accounted for 33.3% of total transported volumes. In manycases, our contracts for natural gas transportation allow us to charge shippersfees for treating, compression, dehydration or services other than processingand conditioning.

*Our Natural GasSales Contracts*

We sell natural gas toother natural gas pipelines, marketing affiliates of integrated oil companiesor other midstream companies, utilities, power producers and end-users. We sellnatural gas under index-related pricing terms with the exception of alimited number of intra-month fixed-price sales arrangements usedfor balancing our portfolio for the month. Transactions under these fixed-pricearrangements are executed to support intra-month changes in operatingconditions, including customer requirements, and not for purposes ofspeculation.

*Our Natural GasProcessing and Conditioning Contracts*

With respect to ournatural gas processing and conditioning services, we contract under thefollowing types of arrangements:

·       *Keep-Whole with Fee Arrangements.  *Underkeep-whole with fee arrangements, we receive natural gas from producers andthird-party transporters, process or condition the natural gas and sellthe resulting NGLs to third parties at market prices. Under these types ofarrangements, 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, 2004, volumes at our Houston CentralProcessing Plant related to this type of fee arrangement accounted for 82.5% oftotal volumes.

·       *Keep-Whole Without Fee Arrangements.*   Underkeep-whole without fee arrangements, we receive natural gas from the produceror 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 fee arrangements” above,except that we do not charge the producer or transporter a conditioning fee. Itis generally not our policy to enter into new keep-whole contracts without feearrangements. For 

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the year ended December 31,2004, volumes at our Houston Central Processing Plant related to this type offee arrangement accounted for 13.8% of total volumes.

·       *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 anagreed upon index-related price for the natural gas, if not redelivered,and an agreed upon percentage of the NGL proceeds. Under these types ofarrangements, our revenues and gross margins increase as NGL prices increase,and our revenues and gross margins decrease as NGL prices decrease. For theyear ended December 31, 2004, volumes at our Houston Central ProcessingPlant related to this type of fee arrangement accounted for 3.3% of totalvolumes.

·       *Fixed Fee, or Tolling, Arrangements.*   Under fixedfee arrangements, producers pay us a fixed fee to process their natural gas. Thesetypes of arrangements require us to pay the producer for the value of NGLsrecovered and to redeliver the residue gas in exchange for a fixed fee. For theyear ended December 31, 2004, volumes at our Houston Central ProcessingPlant related to this type of fee arrangement accounted for less than 0.4% oftotal 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 wheresuch margins are in excess of an agreed-upon amount.

All of our processingagreements allow us to determine, in our sole discretion, whether we process orcondition natural gas. We determine whether to process or condition the naturalgas based upon the price of natural gas and various NGL products. When NGLextraction is uneconomic, NGLs are left in the natural gas stream to themaximum extent allowed by pipeline quality specifications, thus reducing theamount of fuel consumed by the processing plant and the loss in Btus resultingfrom the extraction of the NGLs. When we elect to condition natural gas,typically our natural gas fuel consumption volumes are reduced by approximately79% and the Btu reduction associated with the extraction of NGLs is reduced by94% while our average barrels of NGLs extracted from natural gas is reduced byapproximately 96%. For a detailed discussion of our processing and conditioningcapabilities, please read Item 1, “Business—Copano Processing.”

*Our NGL ProductSales Arrangements*

We use our Sheridan NGLPipeline for transporting butane and natural gasoline mix to an interconnectwith Enterprise Seminole Pipeline where we sell the butane and natural gasolinemix based on market prices for its components. At the tailgate of the plant, wedeliver and sell ethane and propane to Dow Hydrocarbons and Resources Inc. atprices based on published indices, and we deliver and sell stabilizedcondensate to TEPPCO based on an index-related price.

**OurCommercial Relationship with Kinder Morgan Texas Pipeline**

For the year ended December 31,2004, approximately 86% of the natural gas volumes processed or conditioned atour Houston Central Processing Plant were delivered to the plant through theKMTP Laredo-to-Katy pipeline while the remaining 14% were delivered directly tothe plant from our gathering systems. Of the volumes delivered to the plantfrom the KMTP Laredo-to-Katy pipeline, approximately 23% were delivered fromgathering systems controlled by us, while 77% were delivered into KMTP’spipeline from other sources. We refer to the natural gas delivered into KMTP’spipeline from sources other than our gathering systems as “KMTP Gas.” Of thetotal volume of NGLs extracted at the plant during this period, 45% originatedfrom KMTP Gas, while 55% was attributable to gathering systems controlled byus, including our gathering systems connected directly to the plant. Under ourcontractual 

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arrangementrelated to KMTP Gas, we receive natural gas at our plant, process or conditionthe natural gas and sell the NGLs to third parties at market prices. Becausethe extraction 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.

**Our Growth Strategy**

Our growth strategy contemplates complementaryacquisitions of midstream assets in our operating areas as well as capitalexpenditures to enhance our ability to increase cash flows from our existingassets. We intend to pursue acquisitions and capital expenditure projects thatwe believe will allow us to capitalize on our existing infrastructure,personnel and relationships with producers and customers to provide midstreamservices. In the future, we intend to pursue selected acquisitions in new geographicareas, including other areas of Texas, Louisiana and the Gulf of Mexico, 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 capital than many of our competitors that are masterlimited partnerships, or MLPs, because, unlike in a traditional MLP structure,neither our management nor any other party holds incentive distribution rightsthat entitle them to increasing percentages of cash distributions as higher perunit levels of cash distributions are received. We intend to finance futureacquisitions primarily by using the capacity available under our bank creditfacilities and equity or debt offerings or a combination of both. For a moredetailed discussion of our capital resources, please read “—Liquidity andCapital Resources.”

*Acquisition Analysis.  *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.

*CapitalExpenditure Analysis.  *We make capital expenditureseither to maintain our assets or the supply of natural gas volumes to ourassets or for expansion projects to increase our gross margin. Maintenancecapital expenditures are capital expenditures employed to replace partially orfully depreciated assets to maintain the existing operating capacity of ourassets and to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows. Expansioncapital expenditures represent capital expenditures made to expand or increasethe efficiency of the existing operating capacity of our assets. Expansioncapital expenditures include expenditures that facilitate an increase involumes within our operations, whether through construction or acquisition. Expendituresthat reduce our operating costs will be considered expansion capitalexpenditures only if the reduction in operating expenses exceeds costreductions typically resulting from routine maintenance. Our decisions whetherto spend capital on expansion projects are generally based on anticipatedearnings, cash flow and rate of return of the assets.

**ItemsImpacting Comparability of Our Financial Results**

*Our Acquisitions*

Since our inception in1992, we have grown through a combination of 25 acquisitions, including theacquisition of our Houston Central Processing Plant, and significant expansionand enhancement projects 

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relatedto our assets. Our historical acquisitions were completed at different datesand with numerous sellers and were accounted for using the purchase method ofaccounting. Under the purchase method of accounting, results of operations fromsuch acquisitions are recorded in the financial statements only from the dateof acquisition. As a result, our historical results of operations for theperiods presented may not be comparable, as they reflect the results ofoperations of a business that has grown significantly due to acquisitions. Fora more detailed discussion of our acquisition history, please read Item 1, “Business—General.”

*Our ContractRestructuring*

During the second half of 2003 and the first quarterof 2004, we restructured a number of our contracts, including our contract withKMTP, to provide that at least during periods of relatively low processingmargins, we will receive supplemental fees with respect to natural gas thatdoes not meet the downstream transporter’s gas quality specifications. Thesefees provide us additional revenue and compensate us for the services requiredto redeliver natural gas that meets downstream pipeline quality specifications.We expect that the restructured contracts, particularly our contract with KMTP,will help reduce the volatility of our processing segment gross margin.

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**Our Results of Operation**
| ** **                                                | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                | ** ** | **($ in thousands)**             | ** ** |
| Total gross  margin                                       |       | $                                          | 51,501     |   | $ | 31,195 |   | $ | 25,371 |   |
| Operations and  maintenance expenses                      |       | 12,486                                     |       | 10,854 |   | 9,562 |   |
| Depreciation and  amortization                            |       | 7,287                                      |       | 6,091 |   | 5,539 |   |
| General and  administrative expenses                      |       | 9,217                                      |       | 5,849 |   | 4,177 |   |
| Taxes other than  income                                  |       | 770                                        |       | 926 |   | 891 |   |
| Equity in  (earnings) loss from unconsolidated affiliates |       | (419                                       | )          | 127 |   | 584 |   |
| Operating income                                          |       | 22,160                                     |       | 7,348 |   | 4,618 |   |
| Interest and  other financing costs, net                  |       | (23,075                                    | )          | (12,065 | ) | (6,259 | ) |
| Net loss                                                  |       | $                                          | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Segment gross  margin:                                    |       |                                       |       |   |   |   |   |
| Pipelines(1)                                              |       | $                                          | 30,076     |   | $ | 27,551 |   | $ | 18,772 |   |
| Processing                                                |       | 21,425                                     |       | 3,644 |   | 6,599 |   |
| Total gross  margin                                       |       | $                                          | 51,501     |   | $ | 31,195 |   | $ | 25,371 |   |
| Segment gross  margin per unit:                           |       |                                       |       |   |   |   |   |
| Pipelines ($/MMBtu)(1)                                    |       | $                                          | 0.35       |   | $ | 0.29 |   | $ | 0.20 |   |
| Processing:                                               |       |                                       |       |   |   |   |   |
| Inlet throughput ($/MMBtu)(2)                             |       | 0.10                                       |       | 0.02 |   | 0.03 |   |
| NGLs produced ($/Bbl)(2)                                  |       | 3.81                                       |       | 1.37 |   | 1.43 |   |
| Volumes:                                                  |       |                                       |       |   |   |   |   |
| Pipelines—throughput (MMBtu/d)(1)                    |       | 239,770                                    |       | 256,556 |   | 264,349 |   |
| Processing:                                               |       |                                       |       |   |   |   |   |
| Inlet throughput (MMBtu/d)                                |       | 559,939                                    |       | 502,057 |   | 596,520 |   |
| NGLs produced (Bbls/d)                                    |       | 15,373                                     |       | 7,280 |   | 12,656 |   |
| Operations and  maintenance expenses:                     |       |                                       |       |   |   |   |   |
| Pipelines                                                 |       | $                                          | 5,813      |   | $ | 5,161 |   | $ | 4,049 |   |
| Processing                                                |       | 6,673                                      |       | 5,693 |   | 5,513 |   |
| Total operations  and maintenance expenses                |       | $                                          | 12,486     |   | $ | 10,854 |   | $ | 9,562 |   |

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(1)          Excludes results andvolumes associated with our interest in Webb/Duval Gatherers. Volumestransported by Webb/Duval Gatherers were 118,873 MMBtu/d, 108,640 MMBtu/d and89,985 MMBtu/d for the years ended December 31 2004, 2003 and 2002,respectively.

(2)          Representsthe total processing segment gross margin divided by the total inlet throughputor NGLs produced, as appropriate.

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

*Pipelines Segment Gross Margin.  *Pipelinessegment gross margin was $30.1 million for the year ended December 31,2004 compared to $27.6 million for the year ended December 31, 2003,an increase of $2.5 million, or 9.0%. The increase was primarilyattributable to higher average natural gas prices during the year ended December 31,2004 compared to the year ended December 31, 2003, which caused anincrease in margins associated with our index price-related gas purchaseand transportation arrangements. During 2004, the Houston Ship Channel, or HSC,natural gas index price averaged $5.78 per MMBtu compared to $5.24 per MMBtuduring 2003, an increase of $0.54, or 10 %. Additionally, a portion ofthis increase was related to improved contract terms as a result of ourcontract restructuring efforts discussed 

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above, which was partiallyoffset (i) with milder weather during the winter heating portion of thefirst quarter of 2004, which resulted in lower volumes being sold to utilitiesunder high-margin arrangements and (ii) the reduction of relativelylow-margin transportation volumes in the Upper Gulf Coast and Coastal Watersregions.

*Processing Segment Gross Margin.  *Processingsegment gross margin was $21.4 million for the year ended December 31,2004 compared to $3.6 million for the year ended December 31, 2003,an increase of $17.8 million, or 494.4%. For the year ended December 31,2004, we experienced improvements of $19.9 million in our processingsegment gross margin as the result of increased plant utilization and animproved commodity price environment. For a discussion of the commodity priceenvironment, please read “—How We Evaluate Our Operations—Segment Gross Margin”.As a result of unfavorable commodity prices in 2003, the Houston CentralProcessing Plant’s operations were severely curtailed during certain portionsof that period. Processing segment gross margin was further improved as aresult of increased conditioning fee revenue of $1.5 million for the yearended December 31, 2004 compared with the same period in 2003. Thisincrease is attributable to receiving conditioning fee revenues for the fullyear of 2004 versus a partial year of receiving conditioning fee revenues in2003. The increased processing segment gross margin was partially offset by anincrease in processing upgrade payments of $3.6 million to natural gassuppliers, including our pipeline affiliates, for the year ended December 31,2004 and was the result of increased value of processing in 2004.

*Operationsand Maintenance Expenses.  *Operations and maintenanceexpenses totaled $12.5 million for the year ended December 31, 2004compared with $10.9 million for the year ended December 31, 2003, anincrease of $1.6 million, or 14.7%. The increase was primarilyattributable to:

·       higherrepair and maintenance expense totaling $0.6 million at our HoustonCentral Processing Plant ($0.5 million, of which $0.3 million relatedto painting certain facilities, replacing a cooling tower and overhaulingcertain engines) and in our South Texas Region ($0.1 million);

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

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

·       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 ofinstalling additional compression equipment in our South Texas and Upper GulfRegions after December 31, 2003 offset by lower compression rental expenseof $0.2 million as a result of purchasing certain compression equipment weprevious leased.

*Depreciation and Amortization.  *Depreciationand amortization totaled $7.3 million for the year ended December 31,2004 compared with $6.1 million for the year ended December 31, 2003,an increase of $1.2 million, or 19.7%. This increase relates primarily toadditional depreciation and amortization associated with capital expendituresmade after December 31, 2003 including the compression equipment purchasedearlier this year, the Karnes County Gathering System purchased during thethird quarter of 2004 and modifications and enhancements made to the HoustonCentral Processing Plant during the 

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fourth quarter of 2003. Additionally,this increase includes $0.1 million related to pipeline and equipmentretirements.

*General and Administrative Expenses.  *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,an increase 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 associatedwith costs of becoming a public company, including accounting, directors, K-1processing, investors relations and insurance expenses.

*InterestExpense.  *Interest and other financing costs totaled$23.2 million for the year ended December 31, 2004 compared with$12.1 million for the year ended December 31, 2003, an increase of$11.1 million, or 92%. Of this increase, $3.1 million was primarilythe result of our adoption of SFAS No. 150 on July 1, 2003,which required that the value of the payment-in-kind preferred units issued tothe redeemable preferred unitholders in lieu of preferred distributions berecorded as interest expense, whereas before the adoption of Statement ofFinancial Accounting Standard, or SFAS No. 150, this value wasrecorded as a direct increase to accumulated deficit. Similarly, the accretionof the allocated warrant value associated with the redeemable preferred unitswas also recorded as interest expense beginning July 1, 2003. Current yearinterest expense 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 remainingdiscount associated with our purchase of the warrant issued by one of oursubsidiaries to the holder of the term loan. This increase was partially offsetby $1.2 million of lower interest expense related to our credit facilitiesas a result of lower debt outstanding during the year and lower interest rateson the outstanding borrowings.

*Year Ended December 31,2003 Compared with Year Ended December 31, 2002*

*PipelinesSegment Gross Margin.  *Pipelines segment gross marginwas $27.6 million for the year ended December 31, 2003 compared to$18.8 million for the year ended December 31, 2002, an increase of$8.8 million, or 47%.

·       *South Texas Region.  *Our South TexasRegion systems experienced a significant increase in on-system volumes as wellas improved contractual terms resulting in a $4.2 million increase ingross margin. Increased volumes were the result of successful producer drillingactivity in our South Texas Region, as well as the full-year effect of theacquisition of our Live Oak System in May 2002. We also realized fuelsavings within this region as the result of operational modifications made toour Live Oak system.

·       *Upper Gulf Coast Region.  *Grossmargins from our Upper Gulf Coast Region increased $1.6 million. Thisincrease was due both to increased natural gas sales to utilities and powergenerators and increased margins for sales of natural gas to these customers.

·       *Central Gulf Coast Region.  *TheCentral Gulf Coast Region systems experienced an increase in gross margin of$1.9 million. This increase in gross margin resulted from therenegotiation of contracts under more favorable terms and successful drillingby producers under contracts providing favorable unit margins. This increasewas partially offset by a decline in throughput volumes during 2003, which waslargely attributable to our discontinuing purchases of low-margin natural gasfrom third-party pipelines.

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·       *Coastal Waters Region.  *The grossmargin from our Coastal Waters Region increased by $1.1 million. Thisincrease was the result of increased volumes as a result of the full yeareffect of successful drilling activity by a producer in this region.

*ProcessingSegment Gross Margin.  *Processing segment gross marginwas $3.6 million for the year ended December 31, 2003 compared to$6.6 million for the year ended December 31, 2002, a decrease of$3.0 million, or 45%. The decrease was primarily attributable to loweroverall processing margins caused by the significant increase in natural gasprices during 2003 relative to NGL prices, which had an $8.6 millionnegative impact. Although we experienced an approximately 16% decrease in plantinlet volumes during 2003, this decline was largely offset by the approximate29% increase in NGL content associated with such volumes. The reduction in NGLsrecovered by the plant was attributable to the suspension of processing duringportions of the year for economic reasons discussed below. The impact of lowerprocessing margins was partially offset by:

·       $2.1 millionof fees collected during the third and fourth quarters of 2003 under interimprocessing arrangements with KMTP and many of our producers; and

·       thesignificant benefit during the first quarter of 2003 from our suspension ofprocessing at the Houston Central Processing Plant in reaction to a rapidlychanging natural gas pricing environment resulting in approximately$3.5 million of increased processing segment gross margin during the quarter.During the final week of February 2003, our processing segment suspendedprocessing in order to sell natural gas otherwise used by the plant for fueland hydrocarbon shrinkage requirements at spot prices ranging from $6.55 to$24.88 per MMBtu, a significant increase from the February monthly indexof $5.44 per MMBtu. Management estimates that this activity improved processinggross margins by approximately $1.5 million for the month. Our suspensionof processing operations continued in the beginning of March 2003 becausethe March HSC index price of $8.79 per MMBtu rendered processinguneconomic. Commencing March 11, 2003, we were able to purchase naturalgas at spot prices ranging from $4.87 to $6.57 per MMBtu, enabling us to resumeprocessing on that date. These lower gas prices made processing profitable forthe balance of the month. Management estimates that these circumstancesimproved our processing segment gross margin by approximately $2.0 millionfor March 2003.

*Operations and Maintenance Expenses.  *Operationsand maintenance expenses totaled $10.9 million for the year ended December 31,2003 compared with $9.6 million for the year ended December 31, 2002,an increase of $1.3 million, or 14%. The increase was primarilyattributable to (1) an increase of $0.2 million of costs associatedwith operating our Live Oak System for the full year 2003 as opposed to onlyeight months during 2002, (2) additional costs of $0.5 millionassociated with installing additional leased compression equipment on ourCopano Bay System, Live Oak System, Mesteña Grande System and Agua Dulce Systemto support increased natural gas throughput or enhanced service on thesesystems, (3) increased costs of $0.3 million for our Copano BaySystem related to repair, maintenance and insurance costs and (4) anincrease of $0.3 million at our Houston Central Processing Plant primarilyattributable to insurance costs.

*Depreciation and Amortization.  *Depreciationand amortization totaled $6.1 million for the year ended December 31,2003 compared with $5.5 million for the year ended December 31, 2002,an increase of $0.6 million, or 11%. This increase was primarilyattributable to (1) a $0.5 million increase related to the full yearimpact of capital expenditures made in 2002 at our Houston Central ProcessingPlant and depreciation of asset enhancement expenditures made in 2003 to ourCopano Bay System and Agua Dulce System and (2) a $0.1 million increaserelated to a full year of depreciation being recognized during 2003 associatedwith our Live Oak System, which was acquired during May 2002.

*General and Administrative Expenses.  *Generaland administrative expenses totaled $5.8 million for the year ended December 31,2003 compared with $4.2 million for the year ended December 31, 2002,an 

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increase of$1.6 million, or 38%. The increase was primarily due to costs of augmentedinfrastructure ($0.7 million), the hiring of additional staff($0.7 million) and the establishment of a reserve for uncollectiblereceivables ($0.2 million).

*InterestExpense.  *Interest and other financing costs totaled$12.1 million for the year ended December 31, 2003 compared with$6.4 million for the year ended December 31, 2002, an increase of$5.7 million, or 89%. This increase was primarily a result of our July 1,2003 adoption of SFAS No. 150. Additional interest was also accrued withrespect to the senior secured subordinated indebtedness of our processingsegment. This increase was partially offset by lower bank debt outstandingduring the year coupled with lower interest rates on our outstanding bankborrowings.

**General Trends andOutlook**

Our pipeline segment gross margins are influenced bythe price of natural gas and drilling activity in our operating regions. Increasesin natural gas prices have a positive impact on our pipeline margins andconversely, a reduction in natural gas prices negatively impacts our pipelinesegment gross margins. On average, natural gas prices for the last half of 2004have trended upward, and full-year 2004 average natural gas prices were higherthan those in the first half of 2004. Natural gas prices for the first threemonths of 2005 have been higher than the average full-year price in 2004. Volumesof natural gas on our pipelines also impact our pipeline segment gross margins.Increases in volumes gathered or transported positively impact our pipelinesegment gross margins and conversely, reductions in volumes gathered ortransported negatively impact our pipeline segment gross margins. Highernatural gas prices typically encourage drilling activity in our operatingregions. We believe that natural gas prices will continue to fluctuate over thenext twelve months and are likely to remain higher than the 2004 full-yearaverage.

Our processing segment gross margins are influenced bythe price of NGLs in relation to natural gas prices, and the supply of NGLs containedin natural gas delivered to us at our Houston Central Processing Plant. Increasesin NGL prices, relative to natural gas prices, have a positive impact on ourprocessing segment gross margins and, conversely, a reduction in NGL prices,relative to natural gas prices, negatively impacts our processing segment grossmargins. On average, NGL prices, relative to natural gas prices, for the lasthalf of 2004 trended upward and full-year 2004 NGL prices, in relation tonatural gas prices, were higher than those in the first half of 2004. NGLprices in relation to natural gas prices for the first three months of 2005have been above the full-year average price in 2004. The supply of NGLscontained in natural gas delivered to us at our Houston Central ProcessingPlant also impacts our processing segment gross margins. Increases in thesupply of NGLs contained in the natural gas delivered to our plant positivelyimpact our processing segment gross margins if the price of NGLs exceeds thecost of the natural gas required to extract such NGLs. Conversely, reductionsin the supply of NGLs negatively impact our processing segment gross marginsunder such circumstances. We believe that NGL prices, relative to natural gasprices, will continue to fluctuate, but at levels generally above historicalaverages, for full-year 2005.

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 the last ninemonths of 2004 and the first three months of 2005 have trended upwards. Webelieve that interest rates will continue to rise for the remainder of 2005.

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**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.

**Liquidity andCapital Resources**

Cash generated from operations, borrowings under ourcredit facility and funds from private and future public 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 Sheet Arrangements.  *Wehad no off-balance sheet arrangements as of December 31, 2004.

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

·       maintenancecapital expenditures, which are capital expenditures made to replace partiallyor fully depreciated assets to maintain the existing operating capacity of ourassets and to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows; and

·       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 of growth through acquisitions, weanticipate that we will continue to invest significant amounts of capital togrow and acquire assets. We actively consider a variety of assets for potentialacquisitions. For a discussion of the primary factors we consider in decidingwhether to pursue a particular acquisition, please read “—Our GrowthStrategy—Acquisition Analysis.”

During the year ended December 31, 2004, ourcapital expenditures totaled $8.9 million, consisting of $7.1 millionof expansion capital and $1.8 million of maintenance capital. The majorityof the expansion capital expenditures relate to the purchase of compressorunits that we previously leased and the acquisition and integration of ourKarnes County Gathering System and our Runge Gathering System. We expect to fund future capital expenditures withfunds generated from our operations, borrowings under our credit facilities andthe issuance of additional equity or debt as appropriate given marketconditions. We anticipate expending $3.0 million to $4.0 million ofmaintenance capital over the next 12 months.

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*TotalContractual Cash Obligations.  *A summary of our totalcontractual cash obligations as of December 31, 2004, 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                     |       |                                     | $          | 57,000 |   |   |   | $ | — |   |   | $ | 9,000 |   | $ | 48,000 |   |   | $ | — |   |   |
| Interest                            |       |                                     | 8,741      |   |   |   | 2,653 |   |   | 5,683 |   | 405 |   |   | — |   |   |
| Operating Leases                    |       |                                     | 2,305      |   |   |   | 670 |   |   | 804 |   | 688 |   |   | 143 |   |   |
| Total contractual cash  obligations |       |                                     | $          | 68,046 |   |   |   | $ | 3,323 |   |   | $ | 15,487 |   | $ | 49,093 |   |   | $ | 143 |   |   |
|                                     |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

In addition to the contractual obligations noted inthe table above, we have both fixed and variable contracts to purchase naturalgas, which were executed in connection with our natural gas marketingactivities. As of December 31, 2004, we had fixed contractual commitmentsto purchase 364,250 MMBtu of natural gas in January 2005. All ofthese contracts were based on index-related prices. Using these index-relatedprices at December 31, 2004, we had total commitments to purchase$2.1 million of natural gas under such agreements. Our contracts topurchase variable quantities of natural gas at index-related prices rangefrom one month to the life of the dedicated production. During December 2004,we purchased 4,591,203 MMBtu of natural gas under such contracts.

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

*Cash Flows.*

Thefollowing summarizes our cash flows for each of the three years ended December 31,2004, as reported in the historical consolidated statements of cash flows foundin Item 8 of this Annual Report.
| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                            | ** ** | **(In thousands)**                    | ** ** |
| Net cash provided  by operating activities            |       | $                                          | 17,697     |   | $ | 15,296 |   | $ | 8,865 |   |
| Net cash used in  investing activities                |       | (8,920                                     | )          | (6,192 | ) | (16,817 | ) |
| Net cash used in  financing activities                |       | (6,369                                     | )          | (9,633 | ) | (2,591 | ) |
| Net increase  (decrease) in cash and cash equivalents |       | 2,408                                      |       | (529 | ) | (10,543 | ) |
| Cash and cash  equivalents at beginning of year       |       | 4,607                                      |       | 5,136 |   | 15,679 |   |
| Cash and cash  equivalents at end of year             |       | $                                          | 7,015      |   | $ | 4,607 |   | $ | 5,136 |   |

 

*Operating:  *Forthe year ended December 31, 2004, operating cash flows of$17.7 million reflects the net loss of $0.9 million and the followingnon-cash items: depreciation and amortization of $9.3 million,payment-in-kind interest on redeemable preferred units of $6.5 million,accretion and early extinguishment of preferred unitholders warrant value of$9.4 million, payment-in-kind interest and accretion related tosubordinated debt of $1.2 million, equity earnings of unconsolidatedaffiliate of $0.4 million, and working capital decreases of$7.4 million.

For the year ended December 31, 2003, operatingcash flows of $15.3 million reflect a net loss of $4.7 million andthe following non-cash items: depreciation and amortization of$7.0 million, payment-in-kind interest on subordinated debt of$3.9 million, payment-in-kind interest on redeemable preferred units of$3.5 million, accretion of preferred unitholders warrant value of$0.8 million, equity losses of unconsolidated affiliate of$0.1 million and working capital increases of $4.7 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 

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(exclusive of cash andcash equivalents) of $12.3 million. This decrease in the changes inworking capital components (exclusive of cash and cash equivalents) wasprimarily the result of decreased accounts payable as a result of theresolution of a dispute between a royalty owner and an operator from which wepurchase natural gas. As a result of the dispute, we had suspended payments tothe operator. Upon receiving notice that the parties had substantially resolvedtheir dispute, we used additional cash during the second quarter of 2004 whenwe released approximately $6.1 million in suspended funds to pay theoperator for natural gas we had purchased during 2002, 2003 and early 2004.

For the year ended December 31, 2002, operatingcash flows of $8.9 million reflect a net loss of $1.6 million and thefollowing non-cash items: depreciation and amortization of $6.0 million,payment-in-kind interest on subordinated debt of $3.3 million, equitylosses of unconsolidated affiliate of $0.6 million and working capitalincreases of $0.6 million.

The overall increase of $6.4 million in operatingcash flow from 2002 to 2003 was primarily the result of changes in net loss andnon-cash items itemized above of $2.3 million and an increase in workingcapital of $4.1 million. This increase in working capital was primarily aresult of an increase in accounts payable related to suspended payments to awell operator from whom we purchase natural gas, after receiving notificationthat a royalty interest owner had sued the operator. Standard industry practiceand contractual obligations required us to suspend payment to the operatoruntil we received notification that the dispute between the operator and the royaltyowner had been resolved. As a result, our accounts payable increased from 2002to 2003 because we continued to purchase natural gas from the operator, but hadsuspended payment to the operator for these purchases. We received notificationof partial settlement in the second quarter of 2004 at which time we paid theproducer for the majority of the suspended amounts.

*Investing:  *Netcash used in investing activities was $8.9 million, $6.2 million and$16.8 million for the years ended December 31, 2004, 2003 and 2002,respectively. Capital expenditures for additions to property, plant andequipment and acquisitions were:

·       $8.9 millionin 2004, which includes capital expenditures for the acquisition of compressionequipment, the Karnes County Gathering System and the Runge Gathering System aswell as the continued development of our SCADA system.

·       $6.2 millionin 2003, which includes capital expenditures for the modification to ourHouston Central Processing Plant and the development of our SCADA system; and

·       $16.8 millionin 2002, which includes $13.1 million of capital expenditures for ouracquisition of the Live Oak system, the construction of a pipeline connectingour Agua Dulce System with the Webb/Duval Gathering System, the installation ofnew and expansion of existing compressor stations and the performance ofupgrades to our Houston Central Processing Plant, as well as $3.7 millionfor the purchase of additional partnership interests in Webb/Duval Gatherers.

*Financing:  *Netcash used in financing activities was $6.4 million, $9.6 million and$2.6 million for the years ended December 31, 2004, 2003 and 2002,respectively. 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

·       cashdistributions paid to the pre-offering common and preferred unitholders of$4.0 million,

·       $3.4 millionof offering costs, and

·       debtfinancing related costs of $2.5 million.

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Wereceived net proceeds from our initial public offering, includingproceeds from the exercise of the underwriters’ over-allotment option, of$106.95 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 Copano Processing segment, discussed below, by $7.0 million,

·       redeem common units fromcertain existing investors for $13.95 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.

For the year ended December 31,2002, net cash used in financing activities primarily resulted from cashdistributions paid to the pre-offering common and preferred unitholders.

*Description of OurIndebtedness*

*Copano PipelinesCredit Agreement*

Copano Pipelines Group, L.L.C. (“CPG”), a wholly ownedsubsidiary, and certain of Copano Pipelines’ operating subsidiaries have a$100.0 million revolving credit agreement (the “CPG Credit Agreement”),which matures on February 12, 2008. As of December 31, 2004,$48.0 million was outstanding under this revolving credit facility,bearing interest at a weighted average interest rate of 5.416%. We used$6.0 million of the proceeds from our initial public offering in November 2004to reduce the amount outstanding under this facility to $48.0 million. In March 2005,we reduced the balance outstanding under the CPG Credit Agreement to $45.0 million.

Future borrowings under this revolving credit facilityare available for acquisitions, capital expenditures, working capital andgeneral corporate purposes. This revolving 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 or operating surplus distributable to our unitholders.This credit facility is available to be drawn on and repaidwithout restriction so long as CPG is in compliance with the terms of the CPGCredit Agreement, as amended, including certain financial covenants.

The CPG Credit Agreement contains various covenantsthat limit CPG’s and certain of Copano Pipelines’ operating subsidiaries’ability to grant certain liens; make certain loans, acquisitions, capitalexpenditures and investments; make distributions other than from availablecash; merge or consolidate unless CPG and certain of Copano Pipelines’operating subsidiaries are the survivor; or engage in certain assetdispositions, including a sale of all or substantially all of its assets. Additionally,the CPG Credit Agreement limits the ability of CPG and certain of CopanoPipelines’ operating subsidiaries to incur additional indebtedness with certainexceptions, including purchase money indebtedness not to exceed $500,000 tofinance the acquisition of assets, indebtedness not to exceed $500,000 incurredin the ordinary course of business and unsecured indebtedness qualifying assubordinated debt. The CPG Credit

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Agreementalso contains covenants, which, among other things, require CPG and certain ofCopano Pipelines’ operating subsidiaries to maintain specified ratios orconditions as follows:

·       EBITDA(as defined) to interest expense of not less than 3.5 to 1.0;

·       totaldebt to EBITDA of not more than 4.5 to 1.0;

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0;

·       minimumtangible net worth; and

·       positivenet working capital (excluding current debt maturities)

Based upon the senior debt to EBITDA ratio calculatedas of December 31, 2004 (utilizing trailing four quarters’ EBITDA), CPGhad approximately $24.8 million of unused capacity under the CPG CreditAgreement.

The obligations under this revolving credit facilityare secured by first priority liens on substantially all of the assets ofCopano Pipelines and its subsidiaries (other than certain subsidiaries withinsignificant assets) and our interest in Copano Pipelines. Additionally, theobligations under the revolving credit facility are guaranteed by us and CopanoPipelines and its subsidiaries (other than certain subsidiaries withinsignificant assets).

At CPG’s election, interest under this revolvingcredit facility is determined by reference to (1) the reserve-adjustedLondon interbank offered rate, or LIBOR, plus an applicable margin between1.75% and 3% per annum or (2) the prime rate plus, in certaincircumstances, an applicable margin between 0.25% and 1.5% per annum. Interestis payable quarterly for prime rate loans and at the applicable maturity datefor LIBOR loans, except that if the interest period for a LIBOR loan is sixmonths, interest will be paid at the end of each three-month period.

Our managementbelieves that CPG and its subsidiaries were in compliance with the terms of theCPG Credit Agreement as of December 31, 2004. If an event of defaultexists under the credit agreement, the lenders will be able to accelerate thematurity of the credit agreement and exercise other rights and remedies. Each of the following will 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;

·       defaultby us on the payment of any other indebtedness in excess of $0.5 million,or any default in the performance of any obligation or condition with respectto such 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, and failure to pay, one or more adverse judgments in excess of$0.5 million against which enforcement proceedings are brought or that arenot stayed pending appeal; and

·       a change of control (asdefined in the credit agreement).

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*CHC Facility*

Prior to our initial public offering, we financed ourprocessing operations through a $35 million revolving credit facility,which was repaid in February 2004, as well as through a $21.2 millionterm loan entered into in August 2001 (discussed in Note 7 to theConsolidated Financial Statements contained in Item 8 of this Annual Report). Theterm loan would have matured on August 14, 2008 and bore interest at arate of 14%. In November 2004 concurrent with the closing of our initialpublic offering, we used $7.0 million of the proceeds from our initialpublic offering to reduce this balance.

In November 2004, concurrently with the closingof our initial public offering, Copano Houston Central, L.L.C. (“CHC”), awholly owned subsidiary, and the Copano Processing operating subsidiariesestablished a $12.0 million revolving credit facility (the “CHC Facility”).Approximately $9.0 million was drawn under this facility concurrently withthe closing of our initial public offering to retire in full the term loan andthe balance is available to be drawn under the CHC Facility to finance capitalexpenditures (including construction and expansion projects) as well as to meetworking capital requirements of our processing operations. The CHC Facilitydoes not provide for the type of working capital borrowings that would beeligible, pursuant to our limited liability company agreement, to be consideredavailable cash or operating surplus distributable to our unitholders. As of December 31,2004, $9.0 million was outstanding under this revolving credit facility,bearing interest at a weighted average interest rate of 4.77%. In March 2005,we reduced the balance outstanding under the CHC Facility to $8.0 million.

At CHC’s election, interest under the CHC Facility isdetermined by reference to (1) the reserve-adjusted interbankoffered rate, or IBOR, plus an applicable margin between 2.5% and 3.5% perannum or (2) the prime rate plus, in certain circumstances, an applicablemargin of up to 1.5% per annum. Interest is payable quarterly for prime rateloans and at the applicable maturity date for IBOR loans, except that if theinterest period for an IBOR loan is six months, interest will be paid at theend of each three-month period. For additional information regardingrestrictions and covenants under this credit agreement, please read Note 7 tothe Consolidated Financial Statements contained in Item 8 of this AnnualReport.

The obligations under this revolving credit facilityare secured by first priority liens on substantially all of the assets of CHCand its subsidiaries and our interest in CHC. Additionally, CHC and certain ofits subsidiaries are jointly and severally liable as borrowers under thisrevolving credit facility, and the obligations under the CHC Facility areguaranteed by us and by the CHC subsidiaries that are not borrowers under thisfacility.

The CHC Facilitycontains various covenants that limit the ability of CHC and its subsidiariesto:

·       incurindebtedness;

·       grantcertain liens;

·       makecertain loans, acquisitions and investments;

·       makedistributions if a default or event of default exists;

·       changetheir capital structure;

·       mergeor consolidate; or

·       sellall or any material part of their assets.

The CHC Facilityalso contains covenants, which, among other things, require CHC to maintainspecified ratios or conditions as follows:

·       EBITDA(as defined in the credit agreement) to interest expense of not less than 3.25to 1.0;

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·       totalsenior debt to EBITDA of not more than 3.5 to 1.0 at closing, reducing to notmore than 2.75 to 1.0 over the two-year term of the loan;

·       positivenet working capital (excluding current debt maturities);

·       minimumtangible net worth;

·       makemaintenance capital expenditures of not more than $2.5 million percalendar year; and

·       maintainan interest reserve account of at least $1.0 million.

Our managementbelieves that CHC and its subsidiaries were in compliance with the covenantsunder this facility as of December 31, 2004. If an event of default existsunder the credit agreement, the lenders will be able to accelerate the maturityof the credit agreement and exercise other rights and remedies. Each of thefollowing will 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;

·       defaultby us or any of our subsidiaries on the payment of any other indebtedness inexcess of $0.5 million, default by CHC or any of its subsidiaries on thepayment of any other indebtedness in excess of $0.25 million, or, ineither case, any default in the performance of any obligation or condition withrespect to such indebtedness beyond the applicable grace period if the effectof the default is to permit or cause the acceleration of the indebtedness;

·       bankruptcyor insolvency events involving us or our subsidiaries;

·       theentry, and failure to pay, one or more adverse judgments in excess of (a) $0.5 millionin the case of judgments against us or (b) $0.25 million in the caseof judgments against CHC or any of its subsidiaries, and, in each case, againstwhich enforcement proceedings are brought or that are not stayed pendingappeal;

·       achange of control (as defined in the CHC Facility); and

·       anypayment default by any guarantor of its obligations under this revolving creditfacility or revocation of any guaranty.

**Recent Accounting Pronouncements**

In December 2004, the Financial Accounting Standards Board, or FASB, issued SFAS No. 123(revised 2004), or SFAS No. 123(R), “Share Based Payment” 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 intrinsicvalue measurement 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 thefair value of the award on the date of the grant. The standardrequires grant date fair value to be estimated using either an option-pricingmodel that is consistent with the terms of the award or a market observedprice, if such a price exists. Such cost must be recognized over the periodduring which an employee is required to provide services in exchange for theaward (which is usually the vesting period). The standard also requires us toestimate the number of instruments that will ultimately be issued, rather thanaccounting for forfeitures as they occur. We are required to apply SFAS No. 123(R) toall awards granted, modified or settled in the first reporting period after June 15,2005. We are also required to use either the 

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“modified prospectivemethod” or the “modified retrospective method.” Under the modified prospective method, we must recognize compensationcost for all awards granted after we adopt the standard and for the unvestedportion of previously granted awards that are outstanding on that date. Underthe modified retrospective method, we must restate previously issued financialstatements to recognize the amounts we previously calculated and reported on apro forma basis, as if the prior standard had been adopted. See Note 2 to theConsolidated Financial Statements contained in Item 8 of this Annual Report. Underboth methods, we are permitted to use either a straight line or an acceleratedmethod to amortize the cost as an expense for awards with graded vesting. Thestandard permits and encourages early adoption. We have commenced the analysisof the impact of SFAS 123(R), but have not yet decided: (1) whether wewill elect early adoption, (2) if we elect early adoption, at what date wewould do so, (3) whether we will use the modified prospective method orelect to use the modified retrospective method, and (4) whether we willelect to use straight line amortization or an accelerated method. Additionally,we cannot predict with reasonable certainty the number of options that will beunvested and outstanding upon adoption. 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 using the current guidance.

In December 2004, theFASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets an amendment ofAPB No. 29.”  This statement amendsAPB No. 29 to eliminate the exception for nonmonetary exchanges of similarproductive assets and replaces it with a general exception for exchanges ofnonmonetary assets that do not have commercial substance. The statementspecifies that a nonmonetary exchange has commercial substance if the futurecash flows of the entity are expected to change significantly as a result ofthe exchange. This statement is effective for nonmonetary asset exchangesoccurring in fiscal periods beginning after June 15, 2005. Earlierapplication is permitted for nonmonetary asset exchanges occurring in fiscalperiods beginning after the date this statement is issued. Retroactiveapplication is not permitted. We are analyzing the requirements of this newstatement and believe that its adoption will not have any significant impact onour 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, you should 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 3 and 9 to ourConsolidated Financial Statements contained in Item 8 in this Annual Report.

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*Impairment of 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 cost to sell to determine if impairment isrequired. Until the assets are disposed of, an estimate of the fair value isrecalculated 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 aboveassumptions or factors could materially affect our cash flows, which couldrequire us to record an impairment of an asset.

*Asset Retirement 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 have reviewed our long-lived assets forasset retirement obligation, or ARO, liabilities and identified any suchliabilities. These liabilities include ARO liabilities related to (i) right-of-wayeasements over property not owned by us, (ii) leases of certain currentlyoperated facilities and (iii) regulatory requirements triggered by theabandonment or retirement of certain of these assets. As a result of ouranalysis of identified AROs, we are not required to recognize such potentialliabilities. Our rights under our easements are renewable or perpetual andretirement action, if any, is only required upon nonrenewal or abandonment ofthe easements. We currently expect to continue to use or renew all sucheasement agreements and to use these properties for the foreseeable future. Similarly,under certain leases of currently operated facilities, retirement action isonly required upon termination of these leases and we do not expect terminationin the foreseeable future. Accordingly, management is unable to reasonablyestimate and record liabilities for our obligations that fall under theprovisions of SFAS No. 143 because it does not believe that any of theapplicable assets will be retired or abandoned in the foreseeable future. Wewill record AROs in the period in which the obligation may be reasonablyestimated.

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*Equity Method of Accounting.  *Althoughwe own a 62.5% partnership interest in Webb/Duval Gatherers, we account for theinvestment using the equity method of accounting since the minority generalpartners of Webb/Duval Gatherers have substantive participating rights withrespect to the management of Webb/Duval Gatherers.

*RevenueRecognition.  *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.

**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, that addressactivities, events or developments that we expect or anticipate will or mayoccur in the future, including things such as plans for growth of the business,future capital expenditures, competitive strengths, goals, references to futuregoals or intentions 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 are made by us based on our past experience andour perception of historical trends, current conditions and expected futuredevelopments as well as other considerations we believe are appropriate underthe circumstances. Whether actual results and developments in the future willconform to our expectations is subject to numerous risks and uncertainties,many of which are beyond our control. Therefore, actual outcomes andresults could materially differ from what is expressed, implied or forecast inthese statements. Any differences could be caused by a number of factors,including, but not limited to:

·       Ourability to successfully purchase and integrate any future acquired assets oroperations;

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

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

·       Ourability to retain our key producers;

·       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 Securities and Exchange Commission (“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 “—Risk Factors.”  All forward-looking statements included inthis Annual Report and all subsequent written or oral forward-lookingstatements attributable to us or persons acting on our behalf are expresslyqualified in their entirety by these cautionary statements. The forward-lookingstatements speak only as of the date made, other than as required by law, andwe undertake no obligation to publicly update or revise any forward-lookingstatements, whether as a result of new information, future events or otherwise.

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**Risk Factors**

An investment in ourcommon units involves risks associated with our business, regulatory and legalmatters, our limited liability company structure and the tax characteristics ofour common units. The following list of risk factors is not exhaustive.

*Risks Related toOur Business*

·       Wemay not have sufficient cash from operations to pay the minimum quarterlydistribution following establishment of cash reserves and payment of fees andexpenses.

·       Oursuccess depends upon our ability to continually obtain new sources of naturalgas supply, and any decrease in supplies of natural gas could reduce ourability to make distributions to our unitholders.

·       IfKinder Morgan Texas Pipeline’s, or KMTP’s, Laredo-to-Katy pipeline becomesunavailable to transport natural gas to or from our Houston Central ProcessingPlant for any reason, then our cash flow and revenue could be adverselyaffected.

·       Wedepend on certain key producers for a significant portion of our supply ofnatural gas, and the loss of any of these key producers could reduce our supplyof natural gas transported on our pipeline systems and could result in adecline in our revenues and cash available for distribution.

·       Wegenerally do not obtain independent evaluations of natural gas reservesdedicated to our pipeline systems; therefore, volumes of natural gastransported on our pipeline systems in the future could be less than weanticipate, which may cause our revenues and cash available for distribution tobe less than we expect.

·       Wedepend on certain key customers for sales of natural gas and NGLs. To theextent these and other customers reduce the volumes of natural gas and NGLsthey purchase from us, our revenues and cash available for distribution coulddecline.

·       Ourprofitability is dependent upon prices and market demand for natural gas andNGLs, which are beyond our control and have been volatile.

·       Achange in the characterization of some of our assets by federal, state or localregulatory agencies or a change in policy by those agencies may result inincreased regulation of our assets, which may cause our revenues to decline andoperating expenses to increase.

·       Compliancewith pipeline integrity regulations issued by the Texas Railroad Commissioncould result in substantial expenditures for testing, repairs and replacement.

·       Becausewe handle natural gas and other petroleum products in our pipeline andprocessing businesses, we may incur significant costs and liabilities in thefuture resulting from a failure to comply with new or existing environmentalregulations or an accidental release of hazardous substances into theenvironment.

·       Ifwe do not make acquisitions on economically acceptable terms, our future growthand ability to increase distributions will be limited.

·       Expandingour business by constructing new assets subjects us to risks that the projectmay not be completed on schedule, the costs associated with the project may exceedour expectations and additional natural gas supplies may not be availablefollowing completion of the project, which could cause our revenues and cashavailable for distribution to be less than anticipated.

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·       Ifwe are unable to obtain new rights-of-way or the cost of renewing existingrights-of way increases, then we may be unable to fully execute our growthstrategy, which may have an adverse impact on our ability to increasedistributions to our unitholders.

·       Ourbusiness involves many hazards and operational risks, some of which may not befully covered by insurance. If a significant accident or event occurs that isnot fully insured, our operations could be temporarily or permanently impaired,and our liabilities and expenses could be significant.

·       Restrictionsin our subsidiaries’ credit facilities limit their ability to borrow additionalfunds and may limit their ability to make distributions to us, which may limitour ability to make distributions to our unitholders and capitalize onacquisitions and other business opportunities.

·       Dueto our lack of asset diversification, adverse developments in our gathering,treating, processing and transportation businesses would reduce our ability tomake distributions to our unitholders.

*Risks Related to OurStructure*

·       Affiliatesof our management, CSFB Private Equity and EnCap Investments controlled, in theaggregate, a 24.14% interest in us as of December 31, 2004. Ourmanagement, CSFB Private Equity or EnCap Investments may have conflicts ofinterest with us. Our limited liability company agreement limits the remediesavailable to unitholders in the event unitholders have a claim based onconflicts of interest.

·       Ourcap on certain general and administrative expenses expires on December 31,2007 (if not extended by our pre-offering investors). Once the cap expires, ourpre-offering investors will no longer be required to reimburse us for certainamounts in excess of the cap. This expiration could materially reduce the cashavailable for distribution to our unitholders.

·       Escrowsestablished by our pre-offering investors and distributions attributable to thecommon units and subordinated units held by our pre-offering investorsimmediately prior to our initial public offering may be insufficient toreimburse us for all of our general and administrative expenses in excess ofthe cap, which could materially reduce the cash available for distribution toour unitholders.

·       Wemay issue additional common units without unitholder approval, which woulddilute existing ownership interests.

·       Affiliatesof our management, CSFB Private Equity or EnCap Investments may sell units orother limited liability company interests in the trading market, which couldreduce the market price of our outstanding common units.

·       Reimbursementspaid to one of our affiliates will reduce the amount of our available cash onhand at the end of each quarter, and, therefore, reduce the amount of cash thatwe can distribute to our unitholders.

*Tax Risks to CommonUnitholders*

·       Ourtax treatment depends on our status as a partnership for federal income taxpurposes, as well as our not being subject to entity-level taxation byindividual states. If the IRS treats us as a corporation for tax purposes or webecome subject to entity-level taxation, it would substantially reducethe amount of cash available for distribution to our unitholders.

·       Asuccessful IRS contest of the federal income tax positions we take mayadversely affect the market for our common units, and the costs of any contestwill reduce cash available for distribution to our unitholders.

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·       Aunitholder may be required to pay taxes on income from us even if theunitholder does not receive any cash distributions from us.

**Item 7A.**                Quantitative andQualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adversechanges in market rates and prices. The principal market risk to which we areexposed is commodity price risk for natural gas and NGLs. We also incur, to alesser extent, risks related to interest rate fluctuations. We do not engage incommodity energy trading activities.

*Interest Rate Risk.  *Weare exposed to changes in interest rates as a result of our revolving creditfacilities, which had an average floating interest rate of 5.3% as of December 31,2004. We had a total of $57.0 million of indebtedness outstanding underour credit facilities as of December 31, 2004. The impact of a 1% increasein interest rates on this amount of debt would result in an increase ininterest expense and a corresponding decrease in net income of approximately$0.6 million annually.

*Commodity Price Risks.  *Ourprofitability is affected by volatility in prevailing NGL and natural gasprices. Historically, changes in the prices of most NGL products have generallycorrelated with changes in the price of crude oil. NGL and natural gas pricesare volatile and are impacted by changes in the supply and demand for NGLs andnatural gas, as well as market uncertainty. The current mix of our contractualarrangements described above, together with our ability to condition naturalgas during periods of unfavorable processing margins, significantly reduces ourexposure to natural gas and NGL price volatility. Natural gas prices can alsoaffect our profitability indirectly by influencing the level of drillingactivity and related opportunities for our services. For the year ended December 31,2004, the impact on our gross margin of a $0.01 per gallon change (increase ordecrease) in NGL prices would directly result in a change of $1.8 millionto our gross margin and the impact on our gross margin of a $0.10 per MMBtuincrease (decrease) in the price of natural gas would result in a decrease(increase) of $1.5 million to our gross margin  Increases in natural gas prices or reducednatural gas liquids prices could trigger favorable provisions under ourrestructured processing agreement, which is expected to reduce our exposure toadverse processing margins. If processing margins are negative, we can operatethe plant in a conditioning mode such that additional price increases innatural gas would have an anticipated positive impact to our gross margin.

*Credit Risk.  *Weare diligent in attempting to ensure that we provide credit to onlycredit-worthy customers. However, our purchase and resale of natural gasexposes us to significant credit risk, as the margin on any sale is generally avery small percentage of the total sale price. Therefore, a credit loss couldbe very large relative to our overall profitability.

**Item 8.**                        FinancialStatements and Supplementary Data

The Report of IndependentRegistered Public Accounting Firm, Consolidated Financial Statements and supplementaryfinancial data required for this Item are set forth on pages F-1through F-49 of this Annual Report and are incorporated herein byreference.

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

None.

54

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**Item 9A.**                Controls andProcedures

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.

There have been no changesin our internal control over financial reporting (as defined in Rule 13(a)-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.

**Item 9B.**               Other Information

None.

55

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**PART III**

**Item 10.**                 Directors andExecutive Officers of the Registrant

The information requiredby Item 10 is incorporated herein by reference to the applicable information inour Proxy Statement for our 2005 Annual Meeting of Unitholders set forth underthe caption “Election of Directors,” “Our Board of Directors and its Committees”and “Executive Officers” to be filed with the SEC not later than 120 days afterthe 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 2005Annual Meeting of Unitholders set forth under the caption “Board of Directorsand Executive Compensation” to be filed with the SEC not later than 120 daysafter the close of the fiscal year.

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

The information requiredby Item 12, including information concerning ownership and options under ourequity compensation plan for directors and employees, is incorporated herein byreference to our Proxy Statement for our 2005 Annual Meeting of Unitholders setforth under the caption “Security Ownership of Certain Beneficial Owners andManagement” to be filed with the SEC not later than 120 days after the close ofthe fiscal year.

**Item 13.**                 CertainRelationships and Related Parties

The information requiredby Item 13 is incorporated herein by reference to the applicable information inour Proxy Statement for our 2005 Annual Meeting of Unitholders set forth underthe caption “Certain Relationships and Related Transactions” to be filed withthe SEC not later than 120 days after the close of the fiscal year.

**Item 14.**                 PrincipalAccountant Fees and Services

The information required by Item 14 is incorporatedherein by reference to the applicable information in our Proxy Statement forour 2005 Annual Meeting of Unitholders set forth under the caption “PrincipalAccounting Fees and Services” to be filed with the SEC not later than 120 daysafter the close of the fiscal year.

56

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**PART IV**

**Item 15.**                 Exhibits andFinancial 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**

The following documents are filed as a part of thisAnnual Report or incorporated by reference:

Exhibitsnot incorporated by reference to a prior filing are designated by an asterisk(*) and are filed herewith; all exhibits not so designated are incorporatedherein by reference to a prior filing as indicated.
| 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 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).                        |
| 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/Lice 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). |

57

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| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.11*     |   | Second Amendment to  Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the  Copano Controlling Entities, effective March 1, 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.14*     |   | First Amendment to  Employment Agreement between CPNO Services, L.P. and James J.  Gibson, III, effective March 1, 2005.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.15      |   | Lease Agreement dated  August 14, 2003 between Mateo Lueia and Copano Field Services/Agua  Dulce, L.P. (incorporated by reference to Exhibit 10.11 to Amendment  No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 10.16      |   | Lease Agreement dated  January 22, 2003 between Copano/Operations, Inc., Copano  Processing, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano  Pipelines/Hebbronville, L.P. and Copano Field Services/Central Gulf Coast,  L.P. and American General Life Insurance Company (incorporated by reference  to Exhibit 10.12 to Amendment No. 2 to Registration Statement on  Form S-1 filed October 12, 2004).                                                                                                                                                                                                                                                                                                           |

58

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| 10.17 |   | 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).                                                                                              |
|-------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.18 |   | 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).                                                                                               |
| 10.19 |   | 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).                                                                                  |
| 10.20 |   | Form of  Restricted Unit Grant (Directors) (incorporated by reference to  Exhibit 10.1 to Current Report on Form 8-K filed  December 15, 2004).                                                                                                                                                                                                     |
| 10.21 |   | Form of  Grant of Options (incorporated by reference to Exhibit 10.17 to  Quarterly Report on Form 10-Q filed December 21, 2004).                                                                                                                                                                                                                   |
| 10.22 |   | Form of  Restricted Unit Grant (Employees) (incorporated by reference to  Exhibit 4.4 to Registration Statement on Form S-8 filed  February 11, 2005).                                                                                                                                                                                              |
| 10.23 |   | 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).                                                                                                                                                    |
| 10.24 |   | 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). |
| 10.25 |   | 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).                                                                                                                                                                                           |
| 10.26 |   | 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).                                                                                                                                                    |
| 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.                                                                                                                                                                                                                                                |
| 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.

59

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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 31st day of March 2005.
|        | 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 31, 2005 |
| John R. Eckel, Jr.        |          | Chief  Executive Officer (Principal Executive Officer) |       |                |
| /s/ MATTHEW J. ASSIFF          |          | Senior Vice President and Chief Financial Officer      |       | March 31, 2005 |
| Matthew J. Assiff              |          | (Principal  Financial Officer)                         |       |                |
| /s/ LARI PARADEE               |          | Vice President and Controller (Principal Accounting    |       | March 31, 2005 |
| Lari Paradee                   |          | Officer)                                               |       |                |
| /s/ ROBERT L. CABES, JR.  |          | Director                                               |       | March 31, 2005 |
| Robert L. Cabes, Jr.      |          |                                                   |       |                |
| /s/ JAMES G. CRUMP             |          | Director                                               |       | March 31, 2005 |
| James G. Crump                 |          |                                                   |       |                |
| /s/ ERNIE L. DANNER            |          | Director                                               |       | March 31, 2005 |
| Ernie L. Danner                |          |                                                   |       |                |
| /s/ MICHAEL L. JOHNSON    |          | Director                                               |       | March 31, 2005 |
| Michael L. Johnson             |          |                                                   |       |                |
| /s/ SCOTT A. GRIFFITHS         |          | Director                                               |       | March 31, 2005 |
| Scott A. Griffiths             |          |                                                   |       |                |
| /s/ T. WILLIAM PORTER III |          | Director                                               |       | March 31, 2005 |
| T. William Porter III          |          |                                                   |       |                |
| /s/ WILLIAM L. THACKER    |          | Director                                               |       | March 31, 2005 |
| William L. Thacker             |          |                                                   |       |                |

 

60

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**COPANO ENERGY, L.L.C.INDEX TO FINANCIAL STATEMENTS**
|                                                                                                                                                                                      | ** ** | **Page** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|
| **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, 2004 and 2003                                                                                                                   |       |     | F-3 |   |
| Consolidated  Statements of Operations for the years ended December 31, 2004, 2003 and  2002                                                                               |       |     | F-4 |   |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2004, 2003 and  2002                                                                               |       |     | F-5 |   |
| Consolidated  Statements of Members’ Capital and Comprehensive Loss for the years ended  December 31, 2004, 2003 and 2002                                                  |       |     | F-6, F-7 |   |
| Notes  to the Consolidated Financial Statements                                                                                                                                      |       |     | F-8 |   |
| **Webb/Duval  Gatherers Financial Statements:**                                                                                                                                      |       |     |   |   |
| Report of Independent  Registered Public Accounting Firm                                                                                                                             |       |     | F-37 |   |
| Balance  Sheets as of December 31, 2004 and 2003 (unaudited)                                                                                                                    |       |     | F-38 |   |
| Statements  of Operations for the years ended December 31, 2004 and 2003 (unaudited)  and for the period from February 1, 2002 through December 31, 2002              |       |     | F-39 |   |
| Statements  of Cash Flows for the years ended December 31, 2004 and 2003 (unaudited)  and for the period from February 1, 2002 through December 31, 2002              |       |     | F-40 |   |
| Statements  of Partners’ Capital for the years ended December 31, 2004 and 2003  (unaudited)  and for the period from February 1, 2002 through December 31, 2002 |       |     | F-41 |   |
| Notes to Financial Statements                                                                                                                                                        |       |     | F-42 |   |

 

F-1

----

 

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

To the 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”) (formerlyCopano Energy Holdings, L.L.C.) as of December 31, 2004 and 2003, and therelated consolidated statements of operations, members’ capital andcomprehensive loss, and cash flows for each of the three years in the periodended December 31, 2004. These financial statements are the responsibilityof the Company’s management. Our responsibility is to express an opinion onthese financial statements based on our audits.

We conducted our audits in accordance with standardsof 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. The Company is not required to have, nor were we engaged toperform, an audit of its internal control over financial reporting. Our auditincluded consideration of internal control over financial reporting as a basisfor designing audit procedures that are appropriate in the circumstances, butnot for the purpose of expressing an opinion on the effectiveness of theCompany’s internal control over financial reporting. Accordingly, we express nosuch opinion. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements, assessing theaccounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation. We believe ouraudits 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, 2004 and 2003, and theresults of their operations and their cash flows for each of the three years inthe period ended December 31, 2004, in conformity with accountingprinciples generally accepted in the United States of America.

As discussed inNote 3 to the financial statements, effective January 1, 2002, theCompany changed its accounting for goodwill and intangible assets and effectiveJuly 1, 2003, the Company changed its accounting for financial instrumentswith the characteristics of both liabilities and equity.

/s/ Deloitte & Touche LLP

Houston, Texas

March 23, 2005

F-2

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**COPANO ENERGY,L.L.C. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS**
| ** **                                                                                                                                                                             | ** ** | **December 31,**                                       | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|
| ** **                                                                                                                                                                             | ** ** | **2004**                                                    | ** ** | **2003** | ** ** |
| ** **                                                                                                                                                                             | ** ** | **(In thousands, except  unit information)** | ** ** |
| **ASSETS**                                                                                                                                                                             |       |                                                        |       |   |   |
| Current assets:                                                                                                                                                                        |       |                                                        |       |   |   |
| Cash and cash  equivalents                                                                                                                                                             |       | $                                                           | 7,015      |   | $ | 4,607 |   |
| Escrow cash                                                                                                                                                                            |       | 1,000                                                       |       | 1,001 |   |
| Accounts  receivable, net                                                                                                                                                              |       | 37,045                                                      |       | 25,605 |   |
| Accounts  receivable from affiliates                                                                                                                                                   |       | 1,141                                                       |       | 651 |   |
| Prepayments and  other current assets                                                                                                                                                  |       | 1,300                                                       |       | 1,035 |   |
| Total current  assets                                                                                                                                                                  |       | 47,501                                                      |       | 32,899 |   |
| Property, plant  and equipment, net                                                                                                                                                    |       | 119,683                                                     |       | 117,032 |   |
| Intangible assets,  net                                                                                                                                                                |       | 4,469                                                       |       | 4,397 |   |
| Investment in  unconsolidated affiliate                                                                                                                                                |       | 4,371                                                       |       | 4,072 |   |
| Other assets, net                                                                                                                                                                      |       | 2,375                                                       |       | 3,309 |   |
| Total assets                                                                                                                                                                           |       | $                                                           | 178,399    |   | $ | 161,709 |   |
| **LIABILITIES AND MEMBERS’ CAPITAL**                                                                                                                                              |       |                                                        |       |   |   |
| Current liabilities:                                                                                                                                                                   |       |                                                        |       |   |   |
| Accounts payable                                                                                                                                                                       |       | $                                                           | 36,960     |   | $ | 31,369 |   |
| Accounts payable  to affiliates                                                                                                                                                        |       | 127                                                         |       | 1,371 |   |
| Note payable                                                                                                                                                                           |       | 350                                                         |       | — |   |
| Current portion of  long-term debt                                                                                                                                                     |       | —                                                      |       | 7,800 |   |
| Other current  liabilities                                                                                                                                                             |       | 777                                                         |       | 1,960 |   |
| Total current  liabilities                                                                                                                                                             |       | 38,214                                                      |       | 42,500 |   |
| Long-term  debt, net of current portion                                                                                                                                                |       | 57,000                                                      |       | 27,500 |   |
| Subordinated debt                                                                                                                                                                      |       | —                                                      |       | 30,398 |   |
| Other noncurrent  liabilities                                                                                                                                                          |       | 829                                                         |       | 991 |   |
| Redeemable  preferred units ($100 face value, 1,000,000 units authorized, 0 units  and 703,870 units issued and outstanding as of December 31, 2004  and 2003, respectively) |       | —                                                      |       | 60,982 |   |
| Commitments and contingencies (Note 15)                                                                                                                                                |       |                                                        |       |   |   |
| Members’ capital:                                                                                                                                                                 |       |                                                        |       |   |   |
| Common units, no  par value, 7,056,252 units and 1,299,020 units issued and outstanding as of  December 31, 2004 and 2003, respectively                                           |       | 94,325                                                      |       | 3,471 |   |
| Subordinated  units, no par value, 3,519,126 units and 0 units issued and outstanding as of  December 31, 2004 and 2003, respectively                                             |       | 10,379                                                      |       | — |   |
| Common special  units, no par value, 0 units and 154,000 units outstanding as of  December 31, 2004 and 2003, respectively                                                        |       | —                                                      |       | 154 |   |
| Junior units, no  par value, 620,000 units authorized, 0 units and 620,000 units issued and  outstanding as of December 31, 2004 and 2003, respectively                           |       | —                                                      |       | 526 |   |
| Junior special  units, no par value, 0 units and 58,000 units outstanding as of  December 31, 2004 and 2003, respectively                                                         |       | —                                                      |       | 29 |   |
| Paid-in  capital                                                                                                                                                                       |       | —                                                      |       | 12,353 |   |
| Accumulated  deficit                                                                                                                                                                   |       | (21,927                                                     | )          | (17,012 | ) |
| Subscription  receivable                                                                                                                                                               |       | —                                                      |       | (183 | ) |
| Deferred  compensation                                                                                                                                                                 |       | (421                                                        | )          | — |   |
|                                                                                                                                                                                   |       | 82,356                                                      |       | (662 | ) |
| Total liabilities  and members’ capital                                                                                                                                           |       | $                                                           | 178,399    |   | $ | 161,709 |   |

 

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

F-3

----

**COPANO ENERGY,L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS**
| ** **                                                                 | ** ** | **Year Ended December 31,**                      | ** ** |
|----------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                                                 | ** ** | **2004**                                                        | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                 | ** ** | **(in thousands, except unit information)** | ** ** |
| Revenue:                                                                   |       |                                                            |       |   |   |   |   |
| Natural gas sales                                                          |       | $                                                               | 262,317    |   | $ | 315,521 |   | $ | 138,655 |   |
| Natural gas sales—affiliates                                          |       | 557                                                             |       | 10 |   | — |   |
| Natural gas liquids sales                                                  |       | 163,530                                                         |       | 60,307 |   | 77,230 |   |
| Transportation, compression and processing fees                            |       | 9,335                                                           |       | 7,690 |   | 7,704 |   |
| Transportation, compression and processing  fees—affiliates           |       | 75                                                              |       | 33 |   | 46 |   |
| Other                                                                      |       | 1,842                                                           |       | 1,010 |   | 1,261 |   |
| Total revenue                                                              |       | 437,656                                                         |       | 384,571 |   | 224,896 |   |
| Costs and expenses:                                                        |       |                                                            |       |   |   |   |   |
| Cost of natural gas and natural gas liquids                                |       | 381,615                                                         |       | 348,336 |   | 194,640 |   |
| Cost of natural gas and natural gas  liquids—affiliates               |       | 2,465                                                           |       | 2,390 |   | 2,189 |   |
| Transportation                                                             |       | 1,583                                                           |       | 2,469 |   | 2,605 |   |
| Transportation—affiliates                                             |       | 492                                                             |       | 181 |   | 91 |   |
| Operations and maintenance                                                 |       | 12,486                                                          |       | 10,854 |   | 9,562 |   |
| Depreciation and amortization                                              |       | 7,287                                                           |       | 6,091 |   | 5,539 |   |
| General and administrative                                                 |       | 9,217                                                           |       | 5,849 |   | 4,177 |   |
| Taxes other than income                                                    |       | 770                                                             |       | 926 |   | 891 |   |
| Equity in (earnings) loss from unconsolidated  affiliate                   |       | (419                                                            | )          | 127 |   | 584 |   |
| Total costs and expenses                                                   |       | 415,496                                                         |       | 377,223 |   | 220,278 |   |
| Operating income                                                           |       | 22,160                                                          |       | 7,348 |   | 4,618 |   |
| Other income (expense):                                                    |       |                                                            |       |   |   |   |   |
| Interest and other income                                                  |       | 85                                                              |       | 43 |   | 101 |   |
| Interest and other financing costs                                         |       | (23,160                                                         | )          | (12,108 | ) | (6,360 | ) |
| Net loss                                                                   |       | $                                                               | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Basic and diluted* net loss per equivalent unit  (Notes 2 and 10)          |       | $                                                               | (0.35      | ) | $ | (6.21 | ) | $ | (6.77 | ) |
| Basic weighted  average number of equivalent units (Notes 2 and 10)   |       | 2,599                                                           |       | 1,405 |   | 1,339 |   |
| Diluted weighted average  number of equivalent units (Notes 2 and 10) |       | 2,604                                                           |       | 1,405 |   | 1,339 |   |

----

*                    Thepotentially dilutive warrants that were previously held by preferredunitholders and outstanding employee unit options were excluded from thedilutive loss per equivalent unit calculation because to include these equitysecurities would have been anti-dilutive since the Company reported losses forthe periods presented.

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

F-4

----

**COPANO ENERGY,L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS**
| ** **                                                                                                       | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                       | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                       | ** ** | **(in thousands)**                    | ** ** |
| Cash Flows From Operating Activities:                                                                            |       |                                       |       |   |   |   |   |
| Net loss                                                                                                         |       | $                                          | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Adjustments to reconcile net loss to net cash  provided by operating activities:                                 |       |                                       |       |   |   |   |   |
| Depreciation and  amortization                                                                                   |       | 7,287                                      |       | 6,091 |   | 5,539 |   |
| Amortization of debt  issue costs                                                                                |       | 2,000                                      |       | 940 |   | 531 |   |
| Equity in (earnings) loss  from unconsolidated affiliate                                                         |       | (419                                       | )          | 127 |   | 584 |   |
| Payment-in-kind  interest on subordinated debt                                                                   |       | 814                                        |       | 3,908 |   | 3,286 |   |
| 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                                                                                            |       | 53                                         |       | — |   | — |   |
| Deferred rent                                                                                                    |       | (59                                        | )          | — |   | — |   |
| Deferred revenue                                                                                                 |       | (2                                         | )          | — |   | — |   |
| (Increase) decrease in:                                                                                          |       |                                       |       |   |   |   |   |
| Accounts receivable                                                                                              |       | (11,440                                    | )          | (1,150 | ) | (7,517 | ) |
| Accounts receivable from  affiliates                                                                             |       | (370                                       | )          | (504 | ) | 678 |   |
| Interest receivable from  affiliates                                                                             |       | 85                                         |       | — |   | — |   |
| Prepayments and other  current assets                                                                            |       |                                       |       | 162 |   | (699 | ) |
| Increase (decrease) in:                                                                                          |       |                                       |       |   |   |   |   |
| Accounts payable                                                                                                 |       | 5,591                                      |       | 5,101 |   | 8,313 |   |
| Accounts payable to  affiliates                                                                                  |       | (1,244                                     | )          | 439 |   | (158 | ) |
| Other current liabilities                                                                                        |       | (2                                         | )          | 672 |   | (51 | ) |
| Net cash provided by  operating activities                                                                       |       | 17,697                                     |       | 15,296 |   | 8,865 |   |
| Cash Flows From Investing Activities:                                                                            |       |                                       |       |   |   |   |   |
| Additions to property,  plant and equipment and intangible assets                                                |       | (8,590                                     | )          | (6,054 | ) | (9,578 | ) |
| Acquisitions of property,  plant and equipment                                                                   |       | (330                                       | )          | (138 | ) | (3,526 | ) |
| Investment in  unconsolidated affiliate                                                                          |       | —                                     |       | — |   | (3,858 | ) |
| Distributions from  unconsolidated affiliate                                                                     |       | —                                     |       | — |   | 145 |   |
| Net cash used in  investing activities                                                                           |       | (8,920                                     | )          | (6,192 | ) | (16,817 | ) |
| Cash Flows From Financing Activities:                                                                            |       |                                       |       |   |   |   |   |
| Repayments of long-term  debt                                                                                    |       | (34,313                                    | )          | (21,800 | ) | (5,100 | ) |
| Proceeds from long-term  debt                                                                                    |       | 40,000                                     |       | 14,000 |   | 5,200 |   |
| Escrow cash                                                                                                      |       | 1                                          |       | (1 | ) | — |   |
| Repayment of subordinated  debt                                                                                  |       | (15,199                                    | )          | — |   | — |   |
| Repayments of other long-term  obligations                                                                       |       | (991                                       | )          | (89 | ) | (103 | ) |
| Deferred financing costs                                                                                         |       | (2,063                                     | )          | (135 | ) | (107 | ) |
| Payment of subscription  receivable                                                                              |       | 143                                        |       | — |   | — |   |
| Distributions to special  unitholders                                                                            |       | (143                                       | )          | — |   | — |   |
| Distributions to common  unitholders                                                                             |       | (4,000                                     | )          | — |   | (287 | ) |
| Proceeds from initial  public offering of common units, net of underwriting discounts and  commissions of $8,050 |       | 106,950                                    |       | — |   | — |   |
| Payment of offering costs                                                                                        |       | (4,322                                     | )          | (798 | ) | — |   |
| Redemption of preferred  units                                                                                   |       | (78,077                                    | )          | — |   | — |   |
| Distributions to  preferred unitholders                                                                          |       | —                                     |       | (810 | ) | (2,194 | ) |
| Redeem common units                                                                                              |       | (13,950                                    | )          | — |   | — |   |
| Purchase warrants issued  by subsidiary                                                                          |       | (405                                       | )          | — |   | — |   |
| Net cash used in  financing activities                                                                           |       | (6,369                                     | )          | (9,633 | ) | (2,591 | ) |
| Net increase  (decrease) in cash and cash equivalents                                                            |       | 2,408                                      |       | (529 | ) | (10,543 | ) |
| Cash and cash  equivalents, beginning of year                                                                    |       | 4,607                                      |       | 5,136 |   | 15,679 |   |
| Cash and cash  equivalents, end of year                                                                          |       | $                                          | 7,015      |   | $ | 4,607 |   | $ | 5,136 |   |

 

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

F-5

----

**COPANO ENERGY,L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL ANDCOMPREHENSIVE LOSS**
| ** **                                                       | ** ** | **Common**                | ** ** | **Subordinated**  | ** ** | **Common Special**   | ** ** | **Junior**              | ** ** | **Junior Special**   | ** ** |
|------------------------------------------------------------------|------------|---------------------------|------------|-------------------|------------|---------------------------|------------|-------------------------|------------|---------------------------|------------|
| ** **                                                       | ** ** | **Number  of Units** | ** ** | **Common  Units** | ** ** | **Number  of Units** | ** ** | **Subordinated  Units** | ** ** | **Number  of Units** | ** ** | **Common  Special  Units** | ** ** | **Number  of Units** | ** ** | **Junior  Units** | ** ** | **Number  of Units** | ** ** | **Junior  Special  Units** | ** ** |
| ** **                                                       | ** ** | **(In thousands)**   | ** ** |
| **Balance, December 31, 2001**                              |       |                      | 1,299      |              |       | $                         | 3,471      |                    |       | —                    |       |   |   | $ | — |   |   |   | — |   |   |   | $ | — |   |   |   | 620 |   |   | $ | 526 |   |   | — |   |   |   | $ | — |   |   |
| Payment-in-kind preferred distributions                          |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Accretion of preferred units                                     |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Distributions to preferred unitholders                           |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Distributions to common unitholder                               |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Issuance of common and junior special units                      |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | 54 |   |   |   | 54 |   |   |   | — |   |   | — |   |   | 18 |   |   |   | 9 |   |   |
| Subscription receivable                                          |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Net loss                                                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Change in fair value of derivatives used for hedging  purposes   |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Comprehensive loss                                               |       |                      |       |              |       |                      |       |                    |       |                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Balance, December 31, 2002**                              |       |                      | 1,299      |              |       | 3,471                     |       |                    | —     |                      |       |   | — |   |   |   | 54 |   |   |   | 54 |   |   |   | 620 |   |   | 526 |   |   | 18 |   |   |   | 9 |   |   |
| Equity issuance costs (See Note 9)                               |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Payment-in-kind preferred distribution                           |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Accretion of preferred units                                     |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Distributions to preferred unitholders                           |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Issuance common and junior special units                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | 100 |   |   |   | 100 |   |   |   | — |   |   | — |   |   | 40 |   |   |   | 20 |   |   |
| Subscription receivable                                          |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Net loss                                                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Change in fair value of derivatives used for hedging  purposes   |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Comprehensive loss                                               |       |                      |       |              |       |                      |       |                    |       |                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Balance, December 31, 2003**                              |       |                      | 1,299      |              |       | 3,471                     |       |                    | —     |                      |       |   | — |   |   |   | 154 |   |   |   | 154 |   |   |   | 620 |   |   | 526 |   |   | 58 |   |   |   | 29 |   |   |
| Subscription receivable                                          |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Distribution to special unitholders                              |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | (121 | ) |   |   | — |   |   | — |   |   | — |   |   |   | (22 | ) |   |
| Distribution to pre-Offering unitholders                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Unit exchange                                                    |       |                      | 739        |              |       | 2,540                     |       |                    | 3,519      |                      |       |   | 10,379 |   |   |   | (154 | ) |   |   | (33 | ) |   |   | (620 | ) |   | (526 | ) |   | (58 | ) |   |   | (7 | ) |   |
| Issuance of common units to public                               |       |                      | 5,750      |              |       | 115,000                   |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Offering costs                                                   |       |                      | —     |              |       | (13,170                   | )          |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Redeem common units from certain pre-Offering  unitholders  |       |                      | (750       | )                 |       | (13,950                   | )          |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Issuance of restricted units                                     |       |                      | 18         |              |       | 434                       |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Stock-based compensation                                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Net loss                                                         |       |                      | —     |              |       | —                    |       |                    | —     |                      |       |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Comprehensive loss                                               |       |                      |       |              |       |                      |       |                    |       |                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| **Balance, December 31, 2004**                              |       |                      | 7,056      |              |       | $                         | 94,325     |                    |       | 3,519                     |       |   |   | $ | 10,379 |   |   |   | — |   |   |   | $ | — |   |   |   | — |   |   | $ | — |   |   | — |   |   |   | $ | — |   |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

F-6

 

----

**COPANO ENERGY,L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL AND COMPREHENSIVE LOSS (Continued)**
| ** **                                                     | ** ** | **Paid-in  Capital**    | ** ** | **Accumulated  Earnings  (Deficit)** | ** ** | **Subscription  Receivable** | ** ** | **Deferred  Compensation** | ** ** | **Other  Comprehensive  Loss** | ** ** | **Total** | ** ** | **Total  Comprehensive  Income (Loss)** | ** ** |
|----------------------------------------------------------------|------------|-------------------------|------------|--------------------------------------|------------|------------------------------|------------|----------------------------|------------|--------------------------------|------------|-----------|------------|----------------------------------------------|------------|
| ** **                                                     | ** ** | **(In thousands)** | ** ** |
| **Balance, December 31, 2001**                            |       | $                       | 11,095     |                                 |       | $                            | 1,065      |                       |       |                           | $          | —    |       |                                         |       | $ | — |   |   |   | $ | — |   |   | $ | 16,157 |   |   | $ | — |   |   |
| Payment-in-kind preferred distributions                        |       | —                  |       |                                 | (3,853     | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (3,853 | ) |   | — |   |   |
| Accretion of preferred units                                   |       | —                  |       |                                 | (1,379     | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (1,379 | ) |   | — |   |   |
| Distributions to preferred unitholders                         |       | —                  |       |                                 | (2,194     | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (2,194 | ) |   | — |   |   |
| Distributions to common unitholder                             |       | —                  |       |                                 | (287       | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (287 | ) |   | — |   |   |
| Issuance of common and junior special units                    |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | 63 |   |   | — |   |   |
| Subscription receivable                                        |       | —                  |       |                                 | —     |                         |       |                       | (63        | )                              |       |      | —     |                                         |       |   | — |   |   | (63 | ) |   | — |   |   |
| Net loss                                                       |       | —                  |       |                                 | (1,641     | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (1,641 | ) |   | (1,641 | ) |   |
| Change in fair value of derivatives used for hedging  purposes |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | (226 | ) |   | (226 | ) |   | (226 | ) |   |
| Comprehensive loss                                             |       |                    |       |                                 |       |                         |       |                       |       |                           |       |      |       |                                         |       |   |   |   |   |   |   |   | $ | (1,867 | ) |   |
| **Balance, December 31, 2002**                            |       | 11,095                  |       |                                 | (8,289     | )                            |       |                       | (63        | )                              |       |      | —     |                                         |       |   | (226 | ) |   | 6,577 |   |   | — |   |   |
| Equity issuance costs (See Note 9)                             |       | 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                       |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | 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**                            |       | 12,353                  |       |                                 | (17,012    | )                            |       |                       | (183       | )                              |       |      | —     |                                         |       |   | — |   |   | (662 | ) |   | — |   |   |
| Subscription receivable                                        |       | —                  |       |                                 | —     |                         |       |                       | 183        |                           |       |      | —     |                                         |       |   | — |   |   | 183 |   |   | — |   |   |
| Distribution to special unitholders                            |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (143 | ) |   | — |   |   |
| Distribution to pre-Offering unitholders                       |       | —                  |       |                                 | (4,000     | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (4,000 | ) |   | — |   |   |
| Unit exchange                                                  |       | (12,353                 | )          |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | — |   |   | — |   |   |
| Issuance of common units to public                             |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | 115,000 |   |   | — |   |   |
| Offering costs                                                 |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (13,170 | ) |   | — |   |   |
| Redeem common units from certain pre-Offering  unitholders     |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (13,950 | ) |   | — |   |   |
| Issuance of restricted units                                   |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | (434       | )                                            |       |   | — |   |   | — |   |   | — |   |   |
| Stock-based compensation                                       |       | —                  |       |                                 | —     |                         |       |                       | —     |                           |       |      | 13         |                                         |       |   | — |   |   | 13 |   |   | — |   |   |
| Net loss                                                       |       | —                  |       |                                 | (915       | )                            |       |                       | —     |                           |       |      | —     |                                         |       |   | — |   |   | (915 | ) |   | (915 | ) |   |
| Comprehensive loss                                             |       |                    |       |                                 |       |                         |       |                       |       |                           |       |      |       |                                         |       |   |   |   |   |   |   |   | $ | (915 | ) |   |
| **Balance, December 31, 2004**                            |       | $                       | —     |                                 |       | $                            | (21,927    | )                          |       |                           | $          | —    |       |                                         |       | $ | (421 | ) |   |   | $ | — |   |   | $ | 82,356 |   |   |   |   |   |

 

The accompanying notes arean integral part of these consolidated financial statements.

F-7

 

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

**Note 1**—Organization

Copano Energy, L.L.C. (“CE”), a Delaware limitedliability company, was formed in August 2001 as Copano Energy Holdings,L.L.C. (“CEH”) to acquire entities operating under the Copano name since 1992. Tosimplify its corporate structure, on July 27, 2004, CEH caused the mergerof Copano Energy, L.L.C., a then wholly owned subsidiary of CEH, with andinto CEH, with CEH being the surviving entity. In connection with the merger,CEH changed its name to Copano Energy, L.L.C.

CE, through its wholly owned subsidiaries, providesmidstream energy services, including gathering, transportation, treating,processing and conditioning services in the South Texas and Texas Gulf Coastregions (CE and its subsidiaries are collectively referred to as the “Company”).The Company’s natural gas pipelines collect natural gas from designated pointsnear producing wells and transport these volumes to third-partypipelines, the Company’s gas processing plant, utilities and industrialconsumers. Natural gas shipped to the Company’s gas processing plant, either onthe Company’s pipelines or third-party pipelines, is treated to removecontaminants, conditioned or processed into mixed natural gas liquids, or NGLs,and then fractionated or separated into selected component NGL products,including ethane, propane, butane and natural gasoline mix and stabilizedcondensate. The Company also owns an NGL products pipeline extending from theCompany’s gas processing plant to the Houston area. The Company refers to itsnatural gas pipeline operating subsidiaries collectively as “Copano Pipelines”and to its processing and related activities operating subsidiariescollectively as “Copano Processing”.

Copano PipelinesGroup, L.L.C. (“CPG”), a Delaware limited liability company and wholly ownedsubsidiary of CE, owns directly or indirectly all the entities comprisingCopano Pipelines, with the exception of Copano/Webb-Duval Pipeline, L.P. (“CWDPL”),which was conveyed to CE in February 2004. Copano Pipelines entitiesinclude the following:

·       CopanoEnergy Services/Upper Gulf Coast, L.P.

·       CopanoEnergy Services/Texas Gulf Coast, L.P.

·       CopanoField Services/Agua Dulce, L.P. (“Agua Dulce”)

·       CopanoField Services/Central Gulf Coast, L.P. (“CFS/CGC”)

·       CopanoField Services/Copano Bay, L.P.

·       CopanoField Services/Live Oak, L.P. (“CFS/LO”)

·       CopanoField Services/South Texas, L.P.

·       CopanoField Services/Karnes, L.P. (“CFS/Karnes”)

·       CopanoField Services/Upper Gulf Coast, L.P.

·       CopanoPipelines/Hebbronville, L.P. (“Hebbronville”)

·       CopanoPipelines/South Texas, L.P.

·       CopanoPipelines/Texas Gulf Coast, L.P.

·       CopanoPipelines/Upper Gulf Coast, L.P.

·       Copano/Webb-DuvalPipeline, L.P.

F-8

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

**Note 1**—Organization(Continued)

Copano Houston Central, L.L.C. (“CHC”), a Delawarelimited liability company and a wholly owned subsidiary of CE, owns directly orindirectly all the entities comprising Copano Processing which include CopanoProcessing, L.P. and Copano NGL Services, L.P.

On November 15, 2004, the Company completed itsinitial public offering (the “Offering”) of 5,750,000 common units, inclusiveof 750,000 common units that were issued as a result of the underwriters’exercise of their over-allotment option. The common units issued in theOffering were sold at $20.00 per common unit and the net proceeds from theOffering (other than from the underwriters’ exercise of their over-allotmentoption) were used (i) to redeem CE’s redeemable preferred units frompre-Offering investors for $78,077,000 (see Note 9), (ii) to reduceexisting indebtedness under the CPG Credit Agreement by $6,000,000 (see Note7), (iii) to reduce existing indebtedness under the Tejas Credit Agreementby $7,000,000 (see Note 7), (iv) to pay other obligations of $957,000 (seeNote 8) and (v) to pay expenses of the Offering. The Company used netproceeds from the exercise of the underwriters’ over-allotment option to redeemcommon units from certain investors existing prior to the Offering. After thisredemption of common units, pre-Offering investors owned 1,288,252 common unitsand 3,519,126 subordinated units and the public owned 5,750,000 common units(see Note 10).

Concurrent with theclosing of the Offering, CHC entered into a new $12 million secured revolvingcredit facility. At the closing, CHC borrowed $9,000,000 under this facility toretire the remaining balance outstanding under the Tejas Credit Agreement (seeNote 7). Additionally, concurrent with the closing of the Offering, CPG amendedits existing $100 million secured revolving credit facility (see Note 7).

**Note 2**—Summaryof Significant Accounting Policies

*Basis ofPresentation and Principles of Consolidation*

The accompanying consolidated financial statementsinclude the assets, liabilities and results of operations of CE and itssubsidiaries for each of the periods presented. As discussed in Note 4,the assets of CFS/LO were acquired in May 2002 and the assets ofCFS/Karnes were acquired in September and December 2004. Although theCompany owns, through CWDPL, a 62.5% equity investment in Webb/Duval Gatherers(“WDG”), a Texas general partnership, the Company accounts for the investmentusing the equity method of accounting because the minority general partnershave substantive participating rights with respect to the management of WDG(see Note 5). All significant intercompany accounts and transactions areeliminated in the consolidated financial statements.

Copano General Partners, Inc. (“CGP”), a whollyowned indirect subsidiary of CE, is the only entity within the consolidatedgroup subject to federal income taxes. CGP’s operations include (i) itsownership of CWDPL through February 12, 2004 and (ii) its indirectownership of the managing general partner interest in certain of the CopanoPipelines entities. As of December 31, 2004, CGP had a net operating losscarryforward of approximately $265,000, for which a valuation allowance hasbeen recorded. No income tax expense was recognized for the years ended December 31,2004, 2003 and 2002. Except for income allocated to CGP, income is taxabledirectly to the members holding the membership interests in CE.

The number of common unitsoutstanding and per common unit amounts have been restated for all periodspresented to reflect the conversion or exchange of pre-Offering common unitsinto post-Offering common units immediately prior to the completion of theOffering (see Note 10).

F-9

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*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 management believes theestimates are appropriate, actual results can differ from those estimates.

*Cash and Cash Equivalents*

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. Current amounts represent an escrow for theCHC Credit Facility discussed in Note 7.

*Concentration and Credit Risk*

Financial instruments thatpotentially subject the Company to concentrations of credit risk consistprincipally of cash and cash equivalents and accounts receivable.

The Company places itscash and cash equivalents with high-quality institutions and in money marketfunds. The Company derives its revenue from customers primarily in the naturalgas and utility industries. These industry concentrations have the potential toimpact the Company’s overall exposure to credit risk, either positively ornegatively, in that the Company’s customers could be affected by similarchanges in economic, industry or other conditions. However, the Companybelieves that the credit risk posed by this industry concentration is offset bythe creditworthiness of the Company’s customer base. The Company’s portfolio ofaccounts receivable is comprised primarily of mid-size to large domesticcorporate entities.

*Allowance forDoubtful Accounts*

The Company extends creditto customers and other parties in the normal course of business. Estimatedlosses on accounts receivable are provided through an allowance for doubtfulaccounts. In evaluating the level of established reserves, the Company makesjudgments regarding each party’s ability to make required payments, economicevents and other factors. As the financial condition of any party changes,circumstances develop or additional information becomes available, adjustmentsto the allowance for doubtful accounts may be required. The Company hasestablished various procedures to manage its credit exposure, including initialcredit approvals, credit limits and rights of offset. The Company also usesprepayments and guarantees to limit credit risk to ensure that management’sestablished credit criteria are met. The activity in the allowance for doubtfulaccounts 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, 2004  |       |                                           | $          | 200                          |       |                                     |       | $                                        | 202        |   |   |   | $ | (46 | ) |   |   | $ | 356 |   |   |
| Year ended December 31, 2003  |       |                                           | $          | —                       |       |                                     |       | $                                        | 208        |   |   |   | $ | (8 | ) |   |   | $ | 200 |   |   |
| Year ended  December 31, 2002 |       |                                           | $          | —                       |       |                                     |       | $                                        | —     |   |   |   | $ | — |   |   |   | $ | — |   |   |

 

F-10

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*Property, Plant andEquipment*

Property,plant and equipment consist of intrastate gas transmission systems, gasgathering systems, gas processing, conditioning and treating facilities andother related facilities, which are carried at cost less accumulateddepreciation. The Company charges repairs and maintenance against income whenincurred and capitalizes renewals and betterments, which extend the useful lifeor expand the capacity of the assets. The Company calculates depreciation onthe straight-line method principally over 20-year and 30-year estimated usefullives of the Company’s assets. The weighted average useful lives are asfollows:
| Pipelines and equipment             |   | 22 years |   |
|-------------------------------------|--------|----------|--------|
| Gas processing plant and  equipment |   | 29 years |   |
| Office furniture and equipment      |   | 5 years  |   |

 

The Company capitalizes interest on major projectsduring extended construction time periods. Such interest is allocated toproperty, plant and equipment and amortized over the estimated useful lives ofthe related assets.

The Company reviewslong-lived assets for impairment whenever there is evidence that the carryingvalue of such assets may not be recoverable. This review consists of comparingthe carrying value of the asset with the asset’s expected future undiscountedcash flows 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 are less than the asset’s carrying value. Estimates ofexpected future cash flows represent management’s best estimate based onreasonable and supportable assumptions.

*Intangible Assets*

Intangibleassets consist of rights-of-way, easements and an acquired customerrelationship, which the Company amortizes over the term of the agreement orestimated useful life. For the years ended December 31, 2004 and 2003, theweighted average amortization period for the Company’s intangible assets was10.1 years and 9.3 years, respectively. Amortization expense was$434,000, $377,000 and $358,000 for the years ended December 31, 2004,2003 and 2002, respectively. Estimated aggregate amortization expense for eachof the five succeeding fiscal years and thereafter is approximately: *2005—*$420,000; *2006—*$407,000; *2007—*$368,000;*2008—*$300,000; *2009—*$232,000; and *thereafter—*$2,742,000. Intangible assetsconsisted of the following (in thousands):
| ** **                            | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2004**              | ** ** | **2003** | ** ** |
| Rights-of-way  and easements, at cost |       | $                     | 6,552      |   | $ | 6,047 |   |
| Customer relationship                 |       | 725                   |       | 725 |   |
| Less accumulated amortization         |       | (2,808                | )          | (2,375 | ) |
| Intangible assets, net                |       | $                     | 4,469      |   | $ | 4,397 |   |

 

*Other Assets*

Other assets primarily consist of costs associatedwith debt issuance and long-term contracts and are carried on the balancesheet, net of related accumulated amortization. Amortization of other assets is

F-11

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

calculatedusing the straight-line method over the maturity of the associated debt or theexpiration of the contract.

*Transportation andExchange Imbalances*

In the course oftransporting natural gas and natural gas liquids for others, the Company mayreceive for redelivery different quantities of natural gas or natural gasliquids than the quantities actually redelivered. These transactions result intransportation and exchange imbalance receivables or payables that arerecovered or repaid through the receipt or delivery of natural gas or naturalgas liquids in future periods, if not subject to cashout provisions. Imbalancereceivables are included in accounts receivable and imbalance payables areincluded in accounts payable on the consolidated balance sheets and marked-to-marketusing current market prices in effect for the reporting period of theoutstanding imbalances. As of December 31, 2004 and 2003, the Company hadimbalance receivables totaling $454,000 and $380,000 and imbalance payablestotaling $602,000 and $554,000, respectively. Changes in market value and thesettlement of any such imbalance at a price greater than or less than therecorded imbalance results in either an upward or downward adjustment, asappropriate, to the cost of natural gas sold.

*Asset RetirementObligation*

In June 2001, the Financial Accounting StandardsBoard (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143,“Accounting for Asset Retirement Obligations.” This statement requires entitiesto record the fair value of a liability for legal obligations associated withthe retirement obligations of tangible long-lived assets in the period in whichthe obligation is incurred and can be reasonably estimated. When the liabilityis initially recorded, a corresponding increase in the carrying amount of therelated long-lived asset is recorded. Over time, accretion of the liability isrecognized each period, and the capitalized cost is depreciated over the usefullife of the related asset. Upon settlement of the liability, an entity eithersettles the obligation for its recorded amount or incurs a gain or loss onsettlement. The standard became effective for the Company on January 1,2003.

Under the implementation guidelines of SFAS No. 143,the Company has reviewed its long-lived assets for asset retirement obligation(“ARO”) liabilities and identified any such liabilities. These liabilitiesinclude ARO liabilities related to (i) rights-of-way and easements overproperty not owned by the Company, (ii) leases of certain currentlyoperated facilities and (iii) regulatory requirements triggered by theabandonment or retirement of certain of these assets.

As a result of the Company’sanalysis of AROs, the Company determined it was not required to recognize anysuch potential liabilities. The Company’s rights under its easements arerenewable or perpetual and retirement action, if any, is required only uponnonrenewal or abandonment of the easements. The Company currently expects tocontinue to use or renew all such easement agreements and to use theseproperties for the foreseeable future. Similarly, under certain leases ofcurrently operated facilities, retirement action is only required upontermination of these leases and the Company does not expect termination in theforeseeable future. Accordingly, management is unable to reasonably estimateand record liabilities for its obligations that fall under the provisions ofSFAS No. 143 because it does not believe that any of the applicable assetswill be retired or abandoned in the foreseeable future. The Company will recordAROs in the period in which the obligation may be reasonably estimated.

F-12

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*Revenue Recognition*

The Company’s natural gas and natural gas liquidsrevenue is recognized in the period when the physical product is delivered tothe customer at contractually agreed-upon pricing.

A significant portion of the Company’s sale andpurchase arrangements are accounted for on a gross basis in the statements ofoperations as natural gas sales and costs of natural gas, respectively. Thesetransactions are contractual arrangements that establish the terms of the purchaseof natural gas at a specified location and the sale of natural gas at adifferent location at the same or at another specified date. These arrangementsare detailed 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.

The Company occasionally enters into buy/sellarrangements that are accounted for on a net basis in the statements ofoperations as either a natural gas sale or a cost of natural gas, asappropriate.

Transportation,compression and processing-related revenue are recognized in the periodwhen the service is provided and include the Company’s fee-based servicerevenue for services such as transportation, compression and processingincluding processing under tolling arrangements.

*Derivatives*

SFAS No. 133, “Accountingfor Derivative Instruments and Hedging Activities,” as amended, establishesaccounting and reporting standards for derivative instruments, includingcertain derivative instruments embedded in other contracts, and for hedgingactivities. SFAS No. 133 requires that an entity recognize all derivativesas either assets or liabilities in the statement of financial position andmeasure those instruments at fair value. SFAS No. 133 provides that normalpurchases and normal sales contracts are not subject to the statement. Normalpurchases and normal sales are contracts that provide for the purchase or saleof something other than a financial instrument or derivative instrument thatwill be delivered in quantities expected to be used or sold by the reportingentity over a reasonable period in the normal course of business. The Company’sforward natural gas purchase and sales contracts are designated as normalpurchases and sales. Substantially all forward contracts fall within aone-month to five-year term; however, the Company does have certain contractswhich extend through the life of the dedicated production.

*Net Loss Per Unit*

Basic net loss perequivalent unit excludes dilution and is computed by dividing net lossattributable to the common unitholders by the weighted average number ofequivalent units outstanding during the period. Dilutive net loss per unitreflects potential dilution and is computed by dividing net loss attributableto the common unitholders by the weighted average number of equivalent unitsoutstanding during the period increased by the number of additional units thatwould have been outstanding if the dilutive potential units had been exercised.

F-13

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

Basic and diluted net loss per equivalent unit iscalculated as follows (in thousands, except per unit amounts). For periodsprior to the Offering, equivalent units were calculated using the weightedaverage of pre-Offering common units and common special units adjusted by aconversion or exchange factor to reflect the exchange of pre-Offering commonunits for post-Offering common units immediately prior to completion of theOffering (see Note 10).
| ** **                                           | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                           | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net loss                                             |       | $                                          | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Accretion of  preferred units                        |       | —                                     |       | (743 | ) | (1,379 | ) |
| Cash  distributions to preferred unitholders         |       | —                                     |       | (810 | ) | (2,194 | ) |
| Paid-in  kind distributions to preferred unitholders |       | —                                     |       | (2,453 | ) | (3,853 | ) |
| Net loss  available—basic and diluted           |       | $                                          | (915       | ) | $ | (8,723 | ) | $ | (9,067 | ) |
| Basic weighted average equivalent units              |       | 2,599                                      |       | 1,405 |   | 1,339 |   |
| Dilutive weighted  average equivalent units          |       | 2,604                                      |       | 1,405 |   | 1,339 |   |
| Basic and  diluted* net loss per equivalent unit     |       | $                                          | (0.35      | ) | $ | (6.21 | ) | $ | (6.77 | ) |

----

*                    Thepotentially dilutive warrants that were previously held by preferredunitholders and outstanding employee unit options were excluded from thedilutive loss per equivalent unit calculation because to include these equitysecurities would have been anti-dilutive since the Company reported losses forthe periods presented.

CE had 200,000 potentially dilutive employee unitoptions outstanding as of December 31, 2004 and 3,750,000 potentiallydilutive warrants outstanding during the years ended December 31, 2003 and2002. These potentially dilutive option units and warrants were excluded fromthe dilutive loss per equivalent unit calculation because to include theseoptions and warrants would have been anti-dilutive since the Companyreported losses for the years ended December 31, 2004, 2003 and 2002.

Net loss per unit for theyears ended December 31, 2003 and 2002 has not been presented for juniorunits and junior special units as such units were not entitled to share inearnings for the periods presented.

*Accounting forStock-Based Compensation*

The Company uses theintrinsic value method established by Accounting Principles Board Opinion (“APB”)No. 25, “Accounting for StockIssued to Employees” to value unit options issued to employees under theCompany’s long-term incentive plan adopted on November 15, 2004. Inaccordance 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 year ended December 31, 2004, the cost of this stock-basedcompensation program had no impact on the Company’s net loss, as all optionsgranted had an exercise price equal to the market value of the underlyingcommon unit on the date of grant.

F-14

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

**Note 2**—Summaryof Significant Accounting Policies (Continued)

If compensation expenserelated to the issuance of the options had been determined by applying the fairvalue method prescribed in SFAS No. 123, the Company’s net loss and netloss per equivalent unit would have approximated the pro forma amounts below(in thousands):
| ** **                                                                          | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                          | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net loss, as  reported                                                              |       | $                                          | (915       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Less: Stock-based  employee compensation expense determined under fair value method |       | 17                                         |       | — |   | — |   |
| Pro forma net  loss                                                                 |       | $                                          | (932       | ) | $ | (4,717 | ) | $ | (1,641 | ) |
| Loss per  equivalent unit:                                                          |       |                                       |       |   |   |   |   |
| Basic—as reported                                                              |       | $                                          | (0.35      | ) | $ | (6.21 | ) | $ | (6.77 | ) |
| Basic—pro forma                                                                |       | $                                          | (0.36      | ) | $ | (6.21 | ) | $ | (6.77 | ) |
| Diluted—as reported                                                            |       | $                                          | (0.35      | ) | $ | (6.21 | ) | $ | (6.77 | ) |
| Diluted—pro forma                                                              |       | $                                          | (0.36      | ) | $ | (6.21 | ) | $ | (6.77 | ) |

 

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

The fair value of eachunit option granted is estimated on the date of grant using the Black-Scholesoption-pricing model with the following assumptions for 2004 (no options weregranted in 2003 and 2002): exercise price of $20.00, expected volatility rateof 17.86%, risk-free interest rate of 3.12% and expected life of 7 years. TheBlack-Scholes average fair value of options granted in 2004 was $1.44 per unit.

**Note 3**—NewAccounting Pronouncements

*BusinessCombinations and Goodwill*

In June 2001, theFASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwilland Other Intangible Assets.” Pursuant to SFAS No. 141, all businesscombinations initiated after June 30, 2001, are to be accounted for usingthe purchase method of accounting and, therefore, the net assets of an acquiredbusiness are to be recorded at fair value. SFAS No. 142 requires thatgoodwill no longer be subject to amortization over its useful life but, rather,be subject to at least an annual assessment for impairment by applying the fairvalue-based test. Further, SFAS No. 142 requires other acquiredintangible assets be reported separately from goodwill if the benefit of theintangible asset can be sold or transferred or if it is obtained throughcontractual or other legal rights. In accordance with SFAS No. 142, whichbecame effective for the Company on January 1, 2002, the Company testsother intangible assets periodically to determine if impairment has occurred. Animpairment loss is recognized for intangibles if the carrying amount of anintangible asset is not recoverable and its carrying amount exceeds its fairvalue. Upon adoption of SFAS No. 142, the Company re-evaluated the life ofits customer relationship.

F-15

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

**Note 3**—NewAccounting Pronouncements (Continued)

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

In May 2003, the FASBissued SFAS No. 150, “Accounting for Certain Financial Instruments withCharacteristics of Both Liabilities and Equity.” SFAS No. 150 establishesstandards for how an issuer classifies and measures certain instruments withcharacteristics of both liabilities and equity. SFAS No. 150 requires thatan issuer classify such a financial instrument as a liability (or asset in somecircumstances). The Company adopted SFAS No. 150 effective July 1,2003. Upon adoption, the Company began classifying its redeemable preferredunits as a liability and began recording the value of the paid-in-kind (“PIK”) preferredunit distributions issued to the redeemable preferred unitholders as interestexpense, whereas prior to the adoption of SFAS No. 150, thesedistributions were recorded as a direct increase to the accumulated deficit.

*Share Based Payment*

In December 2004, the FASB issued SFAS No. 123(revised 2004), or SFAS No. 123(R), “Share Based Payment” whichestablishes 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 APB No. 25 and generally requires the Company tomeasure the cost of employee services received in exchange for an award ofequity instruments based on the fair value of the award on the date of thegrant.

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 the Company to estimate the number ofinstruments that will ultimately be issued, rather than accounting forforfeitures as they occur. The Company is required to apply SFAS No. 123(R) toall awards granted, modified or settled in the first reporting period after June 15,2005. The Company is also required to use either the “modified prospectivemethod” or the “modified retrospective method.” Under the modified prospectivemethod, the Company must recognize compensation cost for all awards grantedafter the Company adopts the standard and for the unvested portion ofpreviously granted awards that are outstanding on that date. Under the modifiedretrospective method, the Company must restate previously issued financialstatements to recognize the amounts the Company previously calculated andreported on a pro forma basis, as if the prior standard had been adopted. Underboth methods, the Company is permitted to use either a straight line or anaccelerated method to amortize the cost as an expense for awards with gradedvesting. The standard permits and encourages early adoption.

The Company has commencedthe analysis of the impact of SFAS 123(R), but has not yet decided: (1) whetherthe Company will elect early adoption, (2) if the Company elects earlyadoption, at what date the Company would do so, (3) whether the Companywill use the modified prospective method or elect to use the modifiedretrospective method, and (4) whether the Company will elect to usestraight line amortization or an accelerated method. Additionally, the Companycannot predict with reasonable certainty the number of options that will beunvested and outstanding upon adoption. Accordingly, the Company cannotcurrently quantify with precision the effect that this standard would have onthe financial 

F-16

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

**Note 3**—NewAccounting Pronouncements (Continued)

positionor results of operations in the future, except that the Company probably willrecognize a greater expense for any awards that the Company may grant in thefuture than the Company would using the current guidance. If the Company wereto adopt SFAS No. 123(R) using the modified retrospective method, ournet loss would have been approximately $17,000 more than reported in the yearended December 31, 2004.

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

In December 2004, theFASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets an amendment ofAPB Opinion No. 29.” This statement amends APB No. 29 to eliminatethe exception for nonmonetary exchanges of similar productive assets andreplaces it with a general exception for exchanges of nonmonetary assets thatdo 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. This statement iseffective for nonmonetary asset exchanges occurring in fiscal periods beginningafter June 15, 2005. Earlier application is permitted for nonmonetaryasset exchanges occurring in fiscal periods beginning after the date thisstatement is issued. Retroactive application is not permitted. Management isanalyzing the requirements of this new statement and believes that its adoptionwill not have any significant impact on the Company’s financial position,results of operations or cash flows.

**Note 4**—Acquisitions

*CFS/Karnes*

In August 2004, CFS/Karnes acquired a gatheringsystem located in northern Bee and southern Karnes Counties, Texas, forapproximately $305,000, which includes $200,000 cash to the seller and $105,000related to legal and due diligence costs.

In December 2004, CFS/Karnes acquired the Rungegathering system located in Bee, Goliad, Karnes and DeWitt Counties, Texas fromKinder Morgan Tejas Pipeline, L.P. (“KMTP”). This acquisition was accomplishedat no cost to CFS/Karnes (other than $32,000 of legal and due diligencetransaction costs) by dedicating the natural gas supplies connected and flowinginto the Runge gathering system prior to October 1, 2004 to KMTP forpurchase under a long term agreement at a purchase price favorable to KMTP. CFS/Karnesassigned a value of $509,000 to the system and the long term supply agreementbased on the present value of future cash flows of the existing contractsdiscounted at 12%. This amount was set up as deferred revenue which is includedin other noncurrent liabilities on the consolidated balance sheets and is beingamortized on a straight-line basis to natural gas sales over 20 years.

Management allocated theCFS/Karnes purchase price of these asset acquisitions entirely to property,plant and equipment. No pro forma financial information is included as to do sowould not be meaningful.

*CFS/LO*

In May 2002, CFS/LOacquired non-utility gathering assets and contracts from KMTP in Live Oak,Atascosa and Duval Counties, Texas for a cash payment of $3,000,000. Theconsolidated financial statements include the results of operations of CFS/LOfor the period subsequent to the acquisition. Management allocated the purchaseprice of this asset acquisition entirely to property, plant and equipment.

F-17

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

**Note 5**—Investmentin Unconsolidated Affiliate

In November 2001, the Company acquired CWDPL,which owned a 15% general partnership interest in WDG, for $1,300,000 in cash. FromNovember 27, 2001 through January 31, 2002, CWDPL accounted for itsinvestment in WDG using the cost method of accounting.

On February 1, 2002,the Company, through CWDPL, completed the acquisition of an additional 47.5%general partnership interest in WDG for $3,858,000, comprised of $3,750,000cash paid to the seller and $108,000 in legal and other direct acquisitioncosts. As a result of this transaction, CWDPL now holds a 62.5% generalpartnership interest in WDG and became the operator of WDG’s natural gasgathering systems located in Webb and Duval Counties, Texas. Although CWDPLowns a majority interest in WDG and operates WDG, the Company uses the equitymethod of accounting for its investment in WDG because the terms of the generalpartnership agreement of WDG provide the minority general partners substantiveparticipating rights with respect to the management of WDG. The investment inWDG, an unconsolidated affiliate, totaled $4,371,000 and $4,072,000 as of December 31,2004 and 2003, respectively. As of December 31, 2004 and 2003, theinvestment in WDG was carried at $250,000 and $270,000, respectively, less thanthe amount of the underlying equity in net assets (5% and 6%, respectively, oftotal investment of unconsolidated affiliate). This difference is beingamortized into income on a straight-line basis over the life of the underlyingrelated property and equipment of WDG. Equity in earnings (loss) fromunconsolidated affiliate is included in income from operations as the operationsof WDG are integral to the Company.

F-18

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

**Note 5**—Investmentin Unconsolidated Affiliate (Continued)

The summarized financialinformation for investment in unconsolidated affiliate, which is accounted forusing the equity method, is as follows (in thousands):

**Webb/Duval Gatherers**

**SummaryHistorical Financial Information**
| ** **                                                                                          | ** ** | ** **                                                           | ** ** | ** **                                                           | ** ** | **Period from**  | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                          | ** ** | ** **                                                           | ** ** | ** **                                                           | ** ** | **February 1,**  | ** ** |
| ** **                                                                                          | ** ** | ** **                                                           | ** ** | ** **                                                           | ** ** | **2002 through** | ** ** |
| ** **                                                                                          | ** ** | **Year Ended December 31,**                           | ** ** | **December 31,**                                                | ** ** |
| ** **                                                                                          | ** ** | **     2004     ** | ** ** | **     2003     ** | ** ** | **2002**              | ** ** |
| Operating revenue                                                                                   |       |                                                                 | $          | 4,605                                                                |       |                  |       | $ | 3,180 |   |   |   | $ | 2,436 |   |   |
| Operating  expenses                                                                                 |       |                                                                 | (3,504     | )                                                                    |       |                  | (3,017     | ) |   |   | (3,051 | ) |   |
| Depreciation                                                                                        |       |                                                                 | (655       | )                                                                    |       |                  | (591       | ) |   |   | (526 | ) |   |
| Net income (loss)                                                                                   |       |                                                                 | 446        |                                                                 |       |                  | (428       | ) |   |   | (1,141 | ) |   |
| Ownership %                                                                                         |       |                                                                 | 62.5       | %                                                                    |       |                  | 62.5       | % |   |   | 62.5 | % |   |
|                                                                                                |       |                                                                 | 278        |                                                                 |       |                  | (268       | ) |   |   | (713 | ) |   |
| CWDPL share of  management fee charged to WDG                                                       |       |                                                                 | 120        |                                                                 |       |                  | 120        |   |   |   | 110 |   |   |
| Amortization of  difference between the carried investment and the underlying equity in net  assets |       |                                                                 | 21         |                                                                 |       |                  | 21         |   |   |   | 19 |   |   |
| Equity in earnings  (loss) from unconsolidated  affiliate                                           |       |                                                                 | $          | 419                                                                  |       |                  |       | $ | (127 | ) |   |   | $ | (584 | ) |   |
| Distributions  from unconsolidated affiliate                                                        |       |                                                                 | $          | —                                                               |       |                  |       | $ | — |   |   |   | $ | 145 |   |   |
| Current assets                                                                                      |       |                                                                 | $          | 2,348                                                                |       |                  |       | $ | 3,075 |   |   |   |   |   |   |
| Noncurrent assets                                                                                   |       |                                                                 | 8,283      |                                                                 |       |                  | 8,526      |   |   |   |   |   |   |
| Current  liabilities                                                                                |       |                                                                 | (3,237     | )                                                                    |       |                  | (4,653     | ) |   |   |   |   |   |
| Net assets                                                                                          |       |                                                                 | $          | 7,394                                                                |       |                  |       | $ | 6,948 |   |   |   |   |   |   |

 

**Note 6**—Property,Plant and Equipment

Property,plant and equipment consisted of the following (in thousands):
| ** **                                      | ** ** | **December 31,** | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|
| ** **                                      | ** ** | **2004**              | ** ** | **2003** | ** ** |
| Property, plant and  equipment, at cost         |       |                  |       |   |   |
| Pipelines and equipment                         |       | $                     | 93,393     |   | $ | 86,244 |   |
| Gas processing plant and equipment              |       | 48,711                |       | 47,948 |   |
| Construction in progress                        |       | 1,349                 |       | 600 |   |
| Office furniture and equipment                  |       | 1,933                 |       | 1,420 |   |
|                                            |       | 145,386               |       | 136,212 |   |
| Less accumulated  depreciation and amortization |       | (25,703               | )          | (19,180 | ) |
| Property, plant  and equipment, net             |       | $                     | 119,683    |   | $ | 117,032 |   |

 

F-19

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

**Note 7**—Long-Term Debt

Asummary of the Company’s debt follows (in thousands):
| ** **                          | ** ** | **December 31,** | ** ** |
|-------------------------------------|------------|-----------------------|------------|
| ** **                          | ** ** | **2004**              | ** ** | **2003** | ** ** |
| Current portion of long-term  debt: |       |                  |       |   |   |
| CHC Credit Agreement                |       | $                     | —     |   | $ | 7,800 |   |
| Long-term debt:                     |       |                  |       |   |   |
| CPG Credit Agreement                |       | $                     | 48,000     |   | $ | 27,500 |   |
| CHC Facility                        |       | 9,000                 |       | — |   |
| Total                               |       | $                     | 57,000     |   | $ | 27,500 |   |
| Subordinated Debt:                  |       |                  |       |   |   |
| Tejas Credit  Agreement             |       | $                     | —     |   | $ | 30,398 |   |

 

In connection with theOffering discussed in Note 1, the Company used proceeds from the Offering topartially repay its existing long-term indebtedness under the CPG CreditAgreement and, together with borrowings under the new CHC Facility, to retirethe balance outstanding under the Tejas Credit Agreement.

*CPG CreditAgreement*

On November 27, 2001,CPG and certain Copano Pipelines operating subsidiaries entered into a$20,000,000 revolving credit agreement (the “CPG Credit Agreement”) with asyndicate of commercial banks, including Fleet National Bank (“Fleet”), asubsidiary of Bank of America, as the administrative agent. In August 2003,the CPG Credit Agreement was amended to increase the commitment amount from$20,000,000 to $27,500,000. In February and March 2004, CPG and theadditional borrowers amended and restated the CPG Credit Agreement to, amongother things, increase the lenders’ commitment amount to $100 million andextend maturity of the facility to February 12, 2008. In connection withthe February 2004 amendment, CFS/CGC became an additional obligor underthe CPG Credit Agreement when CFS/CGC was conveyed to CPG, and CWDPL ceased tobe an obligor under the credit facility when it was conveyed to CE. Inconnection with the closing of the Offering, on November 15, 2004, the CPGCredit Agreement was amended to, among other things, modify certain financialcovenants to permit CPG to make cash distributions to CE to the extent of “availablecash” (as defined in the CPG Credit Agreement). Additional borrowings under theCPG Agreement in February 2004 were used primarily by CPG to acquireCFS/CGC from CHC, which in turn used the proceeds to pay in full $7,800,000outstanding under the CHC Credit Agreement discussed below and to reduce theoutstanding balance under the Tejas Credit Agreement, discussed below, by$15,199,000. The balance outstanding under the CPG Credit Agreement totaled$48,000,000 and $27,500,000 as of December 31, 2004 and 2003, respectively.Amounts advanced under the CPG Credit Agreement have been used to retireexisting debt, to finance capital expenditures, including constructionprojects, acquisitions of pipelines and investments in unconsolidatedaffiliate, and to meet working capital requirements. Future borrowings underthis facility are available for acquisitions, capital expenditures, workingcapital and general corporate purposes. The CPG credit facility is available tobe drawn on and repaid without restriction so long as CPG is in compliance withthe terms of the CPG Credit Agreement, including certain financial covenants.

F-20

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

**Note 7**—Long-TermDebt (Continued)

The obligations under the CPG Credit Agreement aresecured by first priority liens on substantially all of the assets of CPG andits subsidiaries (other than certain subsidiaries with insignificant assets)and CE’s interest in CPG. Additionally, the obligations under the CPG CreditAgreement are guaranteed by CE and CPG and its subsidiaries (other than certainsubsidiaries with insignificant assets).

The CPG CreditAgreement contains various covenants that limit CPG and certain CopanoPipelines operating subsidiaries’ ability to grant certain liens; make certainloans, acquisitions, capital expenditures and investments; make distributionsother than from available cash; merge or consolidate unless CPG and certainCopano Pipelines operating subsidiaries are the survivor; or engage in certainasset dispositions, including a sale of all or substantially all of its assets.Additionally, the CPG Credit Agreement limits the ability of CPG and certainCopano Pipelines operating subsidiaries to incur additional indebtedness withcertain exceptions, including purchase money indebtedness not to exceed$500,000 to finance the acquisition of assets, indebtedness not to exceed$500,000 incurred in the ordinary course of business and unsecured indebtednessqualifying as subordinated debt. The CPG Credit Agreement also containscovenants, which, among other things, require CPG and certain Copano Pipelinesoperating subsidiaries to maintain specified ratios or conditions as follows:

·       EBITDA(as defined) to interest expense of not less than 3.5 to 1.0;

·       totaldebt to EBITDA of not more than 4.5 to 1.0;

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0;

·       minimumtangible net worth; and

·       positivenet working capital (excluding current debt maturities)

Based upon the senior debt to EBITDA ratio calculatedas of December 31, 2004 (utilizing trailing four quarters’ EBITDA), CPGhad approximately $24,865,000 of unused capacity under the CPG CreditAgreement.

Management believes that CPG and its subsidiaries arein compliance with the financial covenants under the CPG Credit Agreement as ofDecember 31, 2004. If an event of default exists under the creditagreement, the lenders will be able to accelerate the maturity of the creditagreement and exercise other rights and remedies.

At CPG’s election, interest under this credit facilityis 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. The interest is payablequarterly for prime interest 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. During 2004,2003 and 2002, the effective average interest rate on borrowings under the CPGCredit Agreement was 4.01%, 3.72% and 4.97%, respectively. A quarterlycommitment fee of between 0.375% and 0.5% per annum is charged on the unusedportion of the credit facility and was 0.5% at December 31, 2004 and 2003.

Interest and other financing costs related to the CPGCredit Agreement totaled $2,971,000, $1,181,000 and $1,043,000 for the yearsended December 31, 2004, 2003 and 2002, respectively. CPG additionallyincurred other costs in connection with this credit facility, includingreimbursement of fees 

F-21

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

**Note 7**—Long-TermDebt (Continued)

paid byFleet for legal and other professional services in connection with theestablishment of the facility and subsequent amendments. These costs are beingamortized over the remaining term of the CPG Credit Agreement, and as of December 31,2004 and 2003, the unamortized portion of debt issue costs totaled $1,736,000and $330,000, respectively.

*CHC CreditAgreement*

In November 2001, CHC and its then subsidiariesentered into a $35 million credit agreement (the “CHC Credit Agreement”) with asyndicate of commercial banks. In February 2004, this credit facility waspaid in full and terminated using proceeds from the conveyance of a CFS/CGC toCPG discussed above. Amounts advanced under the CHC Credit Agreement were usedto finance debt issue costs and capital expenditures, including constructionprojects and the acquisition of the CHC assets, and to meet working capitalrequirements.

Interest and otherfinancing costs related to the CHC Credit Agreement totaled $446,000,$1,488,000 and $2,031,000 for the years ended December 31, 2004, 2003 and2002, respectively. CHC additionally incurred other costs in connection withthis credit facility, including reimbursement of fees paid by Fleet for legaland other professional services in connection with establishment of thefacility and subsequent amendments. These costs were being amortized over theremaining term of the CHC Credit Agreement, and as of December 31, 2003,the unamortized portion of debt issue costs totaled $396,000. In February 2004,effective with the early termination of this agreement, the Company charged$314,000 to interest expense, representing the balance of the unamortized debtissue costs.

*CHC Facility*

Concurrent with the closing of the Offering, on November 15,2004, CHC and certain of its subsidiaries entered into a $12 million securedrevolving credit facility (the “CHC Facility”) with Comerica Bank due January 31,2007. At the closing, CHC borrowed $9,000,000 under this facility to retire theremaining balance outstanding under the Tejas Credit Agreement discussed below.CHC expects to use the remaining amount of this credit facility to financecapital expenditures (including construction and expansion projects) as well asmeet working capital requirements of its processing operations.

The obligations under this revolving credit facilityare secured by first priority liens on substantially all of the assets of CHCand its subsidiaries and CE’s interest in CHC. Additionally, CHC and certain ofits subsidiaries are jointly and severally liable as borrowers under thisrevolving credit facility, and the obligations under the revolving creditfacility are guaranteed by CE and by the CHC subsidiaries that are notborrowers under this facility.

The CHC Facilitycontains various covenants that limit the ability of CHC and its subsidiariesto incur indebtedness (excluding current accounts payable arising in the normalcourse of business and purchase money indebtedness not to exceed $500,000 forany fiscal year); grant certain liens; make certain loans, acquisitions andinvestments; make distributions if a default or event of default exists; changetheir capital structures; merge or consolidate; or sell all or any materialpart of their assets. Additionally, the CHC Facility contains covenants, which,among other things, require CHC and its subsidiaries to maintain specifiedratios or conditions as follows:

·       EBITDA(as defined) to interest expense of not less than 3.25 to 1.0;

F-22

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

**Note 7**—Long-TermDebt (Continued)

·       totalsenior debt to EBITDA of not more than 3.5 to 1.0 at closing, reducing to notmore than 2.75 to 1.0 over the two-year term of the loan;

·       positivenet working capital (excluding current debt maturities);

·       minimumtangible net worth;

·       makemaintenance capital expenditures of not more than $2.5 million percalendar year; and

·       maintainan interest reserve account of at least $1.0 million.

At CHC’s election, interest under this revolvingcredit facility is 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. Interest is payable quarterly forprime rate loans and at the applicable maturity date for IBOR loans, exceptthat if the interest period for an IBOR loan is six months, interest will bepaid at the end of each three-month period. During 2004, the effectiveaverage interest rate on borrowings under the CHC Facility was 4.77%. Aquarterly commitment fee of between 0.3% and 0.5% per annum is charged on theunused portion of the credit facility and was 0.3% at December 31, 2004.

Interest and other financing costs related to the CHCFacility totaled $69,000 for the year ended December 31, 2004. CHCadditionally incurred other costs in connection with this credit facility,including reimbursement of fees paid by Comerica Bank for legal and otherprofessional services in connection with establishment of the facility. Thesecosts were being amortized over the term of the CHC Facility, and as of December 31,2004, the unamortized portion of debt issue costs totaled $188,000.

Management believes thatCHC and its subsidiaries are in compliance with the covenants under the CHCFacility as of December 31, 2004. If an event of default exists under thecredit agreement, the lenders will be able to accelerate the maturity of thecredit agreement and exercise other rights and remedies.

*Tejas CreditAgreement*

In 2001, CHC and its then subsidiaries and TejasEnergy NS, LLC (“Tejas”) entered into a subordinated credit agreement (the “TejasCredit Agreement”) which provided for a $21.2 million original subordinatedterm loan. CHC and its then subsidiaries used the amounts borrowed under theTejas Credit Agreement in partial payment of the acquisition price for certainassets acquired from Tejas on August 14, 2001, including the Company’s gasprocessing plant. In connection with the Tejas Credit Agreement, CHC issued awarrant to Tejas (the “Tejas Warrant”), which provided Tejas the right toacquire up to 10% of the membership interests (100,000 equity membershipinterests) of CHC.

In 2003, the CHC Borrowers issued an additional$850,000 subordinated note under the Tejas Credit Agreement to Tejas inexchange for certain modifications to the agreement and final settlement ofpurchase price adjustments related to the acquisition of the assets from Tejas.In February 2004 and upon termination of the CHC Credit Agreementdiscussed above, the CHC borrowers and Tejas further amended and restated theTejas Credit Agreement to provide for (i) the prepayment without penaltyof $15,199,000 of principal and interest outstanding under the agreement, (ii) therelease of CFS/CGC as a borrower under the agreement and (iii) the grantto Tejas of a first priority security interest in the assets of CHC and theremaining borrowers, with the exception of certain working capital interests. Inconnection with the amended credit facility, the exercise price of the TejasWarrant was repriced at $41.24 per 

F-23

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

**Note 7**—Long-TermDebt (Continued)

membership interest, or$4,124,000 in the aggregate. As a result of this repricing, CHC assigned anallocated value of $395,000 to the warrant based on the repurchase price of thewarrant, which was $405,000. The allocated warrant value amount was recorded asa discount against the remaining balance of the amount outstanding under theTejas Credit Agreement and as an other noncurrent liability.

The balance of the amount outstanding under the TejasCredit Agreement of $16,013,000 was repaid in full on November 15, 2004,concurrent with the completion of the Offering and the closing of the CHC Facilitydiscussed above. CHC used $9,000,000 borrowed under the CHC Facility and$7,000,000 of Offering proceeds to retire the debt outstanding under the TejasAgreement. CHC used cash on hand to repurchase the Tejas Warrant for $405,000. Asa result of repurchasing the Tejas Warrant, the Company recorded additionalinterest expense of $330,000 in November 2004, which represented the writeoff of the remaining discount associated with the Tejas Warrant as suchredemption is considered an early extinguishment of debt.

Borrowings under the TejasCredit Agreement bore interest at 14% per annum, payable quarterly. Pursuant tothe modified terms of the agreement, interest accrued through March 31,2004 was paid by the issuance of payment-in-kind notes, or PIK notes. After March 31,2004, CHC made all interest payments in cash. Interest expense totaled$2,214,000, $3,908,000 and $3,286,000 for the years ended December 31,2004, 2003 and 2002, respectively.

*ScheduledMaturities of Long-term Debt*

Scheduledmaturities of long-term debt as of December 31, 2004 were as follows (inthousands):
| **Year** | ** ** | ** ** | ** ** | **Principal  Amount** | ** ** |
|----------|------------|------------|------------|-----------------------|------------|
| 2005     |       | $          | —     |                  |
| 2006     |       | —     |       |
| 2007     |       | 9,000      |       |
| 2008     |       | 48,000     |       |
|     |       | $          | 57,000     |                  |

 

**Note 8**—OtherLong-Term Liabilities

During May 1996, AguaDulce purchased gathering pipelines and related assets for $6,000,000 in totalconsideration, of which $4,800,000 was paid in cash and $1,200,000 payablewithout interest, based upon volumes of gas transported through the system. Asof December 31, 2003, the balance of Agua Dulce’s obligation totaled$991,000. The balance, if any, was payable in 2006, or sooner, upon sale of thesystem or the date on which Agua Dulce and its affiliates participate asissuers of equity securities in a registered public offering. The Company used$957,000 of Offering proceeds to pay the outstanding balance under thisarrangement in November 2004.

**Note 9**—RedeemablePreferred Units

Through a series of transactions occurring between August 2001and November 2001, CE issued redeemable preferred units in considerationfor $60,000,000 in cash. The cash proceeds from these issuances were usedprimarily to fund the asset acquisition from Tejas, the acquisition of theminority 

F-24

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

**Note 9**—RedeemablePreferred Units (Continued)

interests in certainpredecessor entities and construction costs related to the Hebbronvillepipeline assets. For the first four years following the initial issuance of thepreferred units, CE had the right to pay the quarterly distributions inpreferred units at a 10% rate. Except for cash distributions of $810,000 and$2,194,000 during the years ended December 31, 2003 and 2002,respectively, the board elected to pay the preferred distributions in preferredunits for all required quarterly distributions, thereby increasing the numberof preferred units and aggregated amount outstanding. As of December 31,2003, preferred units issued and outstanding totaled 703,870 with an aggregateface value of $70,387,000.

Additionally, the preferred unitholders were issuedwarrants to purchase up to 3,750,000 common units of CE exercisable at a priceof $16 per unit until August 14, 2011. Proceeds from the issuance of thepreferred units were allocated between the warrants and the preferred unitsbased on their respective fair values. The fair value of each warrant as of thedate of grant was $4.34 using the Black-Scholes option pricing model andthe following assumptions: exercise price of $16.00, expected volatility rateof 19%, risk-free interest rate of 4.97% and expected life of10 years. The Company used the Black-Scholes warrant value to assignan allocated 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 3) through the mandatoryredemption date. As of December 31, 2003, the remaining balance of thediscount amount totaled $9,405,000.

Prior to the closing of the 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 10) of CE 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, the Company recorded additional interest expense of$7,946,000 in November 2004, which represented the write off of theremaining discount associated with the redeemable preferred units as suchredemption is considered an early extinguishment of debt.

Additionally, CE 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 redeemablepreferred units. The unamortized portion of these debt issue costs totaled$1,135,000 as of December 31, 2003. As a result of the redemption of thepreferred units using proceeds from the Offering, CE wrote off the unamortizedbalance of issuance costs associated with the redeemable preferred units of$921,000.

**Note 10**—Members’Capital

*Common Units andSubordinated Units After the Offering*

On November 15, 2004, immediately prior to thecompletion of the Offering, (i) Copano Partners L.P. (“Copano Partners”),an entity controlled by Mr. John R. Eckel, Jr., Chairman of the Boardof Directors

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

**Note 10**—Members’Capital (Continued)

and Chief ExecutiveOfficer of the Company, exchanged its common units and junior units for 763,221common units and 1,317,733 subordinated units representing approximately 19.71%of the outstanding units of CE upon completion of the Offering including theexercise of the underwriters’ over-allotment option and (ii) two executiveofficers exchanged their common special units and junior special units for anaggregate of 63,911 common units and 110,345 subordinated units representingapproximately 1.65% of the outstanding units of CE upon completion of theOffering including the exercise of the underwriters’ over-allotment option. Additionallyas discussed in Note 9, on November 15, 2004, immediately prior to thecompletion of the Offering, the preferred unitholders exchanged their warrantsfor an aggregate of 1,211,120 common units and 2,091,048 subordinated units. Afterredemption of certain common units received by the former preferred unitholdersusing proceeds from the underwriters’ exercise of the over-allotment option,the former preferred unitholders held an aggregate of 461,120 common units and2,091,048 subordinated units representing approximately 24.17% of theoutstanding units of CE upon completion of the Offering including the exerciseof the underwriters’ over-allotment option.

On November 15, 2004, CE completed the Offeringby issuing 5,750,000 common units at $20.00 per common unit representing 54.46%of the outstanding units of CE. Expenses of the Offering (includingunderwriting discounts and commissions of $8,050,000) totaled $13,170,000. Afterthe redemption of 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.

Subordinated unitsrepresent limited liability interests in CE, and holders of subordinated unitsexercise the rights and privileges available to unitholders under the limitedliability company agreement. All 3,519,126 subordinated units outstanding afterthe Offering and as of December 31, 2004 were held by pre-Offeringinvestors and represented approximately 33% of total units outstanding afterthe Offering. Subordinated units, during the subordination period, willgenerally receive quarterly cash distributions only when the common units havereceived a minimum quarterly distribution of $0.40 per unit for each quartersince the commencement of operations. Subordinated units will convert intocommon units on an one-for-one basis when the subordination periodends. Pursuant to CE’s limited liability company agreement, the subordinationperiod will extend until the first day of any quarter beginning after December 31,2006 that each of the following financial tests is met: (1) distributionsof “available cash from operating surplus” (as defined) on each of theoutstanding common units and subordinated units for the two consecutivefour-quarter periods immediately preceding that date equaled or exceeded theminimum quarterly distribution; (2) the “adjusted operating surplus” (asdefined) generated during the two consecutive four-quarter periods immediatelypreceding that date equaled or exceeded the sum of the minimum quarterlydistributions on all outstanding common units and subordinated units; and (3) thereare no arrearages in payment of the minimum quarterly distributions on thecommon units.

*Common Units andJunior Units Prior to the Offering*

In transactions occurring on August 14, 2001 and November 27,2001, CE issued 1,299,020 (as restated for the conversion related to theOffering) common units and 620,000 junior units to Copano Partners in exchangefor general and limited partnership interests in certain operating entities ofCE. Prior to the completion of the Company’s Offering, a common unitholdercould not receive any distributions until the preferred unitholders had beenredeemed in full, other than distributions for any fiscal year, in amounts

F-26

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

**Note 10**—Members’Capital (Continued)

equal tonet taxable income of such unitholder as reflected on its Schedule K-1multiplied by the maximum federal income tax rate then in effect. Juniorunitholders were entitled to share in distributions only after preferred unitshad been redeemed in full and after common unitholders had received adistribution of $20 per common unit.

*Common SpecialUnits and Junior Special Units Prior to the Offering*

Effective January 2002, 212,000 nonvoting specialunits of CE were designated, 154,000 of which were designated as common specialunits and 58,000 of which were designated as junior special units. Of thedesignated amounts, 54,000 common special units and 18,000 junior special unitswere sold, effective January 2002, to an executive officer of the Companyand, effective April 1, 2003, an additional 100,000 common special unitsand 40,000 junior special units were sold to another executive officer of theCompany. The acquisition price for the common special units and the juniorspecial units was $1.00 per unit and $0.50 per unit, respectively. The initialpurchase of the 72,000 special units issued effective January 2002 to anexecutive officer was financed by a subscription receivable. The secondpurchase of the 140,000 special units issued effective April 1, 2003 toanother executive officer was financed by a subscription receivable, one third,or $40,000, of which was forgiven on April 1, 2004.

On July 30, 2004, Copano/Operations, Inc. (“CopanoOperations”), an entity controlled by Mr. Eckel and which providesmanagement, operations and administrative support services to the Company,loaned these two executive officers a total of $143,000. These officers usedthe loan proceeds to pay CE for the balance of the acquisition price for thespecial 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 of the Company, (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 reduced by an amount equal to the number of commonspecial units multiplied by $16.

*Distributions*

On July 30, 2004, CE 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 ofexisting warrants, common units, common special units, junior units and juniorspecial units for new common units and subordinated units and prior to thecompletion of the Offering to the public, CE made a special distribution topre-Offering unitholders totaling $4,000,000, which the pre-Offeringunitholders placed in escrow accounts. These escrowed funds are available tofund general and administrative expenses in excess of limits and for periodsestablished in the limited liability company agreement, and any unused fundswill revert to the pre-Offering unitholders.

The holders of the commonand subordinated units are entitled to participate in distributions. The commonunits have the right to receive a minimum quarterly distribution of $0.40 perunit, plus any arrearages on the common units, before any distribution is madeto the holders of the subordinated units. Subordinated units do not accruedistribution arrearages. After the expiration of the subordination period,common units will no longer be entitled to arrearages.

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

**Note 10**—Members’Capital (Continued)

*Employee IncentivePlan*

In November 2004, CEadopted a long-term incentive plan for its directors, employees and employeesof its affiliates who perform services for CE. For purposes of the plan, CE’saffiliates include Copano Operations. The plan consists of four components: restrictedunits, phantom units, unit options and unit appreciation rights and limits thenumber of units that may be delivered pursuant to awards to 800,000 units,provided no more than 25% of such units (subject to certain adjustments) may bedelivered as payment with respect to restricted units and phantom units. Theplan is administered by the compensation committee of CE’s board of directors.

*Unit Options*

Unit options will have an exercise price that may notbe less than the fair market value of the underlying units on the date of grant.In general, unit options granted will become exercisable over a perioddetermined by the compensation committee. In addition, unit options will becomeexercisable upon a change in control of CE, unless provided otherwise by thecompensation committee.

On November 15, 2004, CE granted all employees,excluding Mr. Eckel, a total of 200,000 unit options to purchase an equalnumber of common units at $20.00 per unit. 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. Outstandingoptions have remaining contractual lives of approximately 10 years at December 31,2004.

Asummary of the unit option activity for the year ended December 31, 2004is provided below:
| ** **                                      | ** ** | **December 31, 2004** | ** ** |
|-------------------------------------------------|------------|---------------------------------|------------|
| ** **                                      | ** ** | **Number of  units ** | ** ** | **Weighted  average  exercise  price ** | ** ** |
| Outstanding,  beginning of period               |       | —                          |       |   | — |   |   |
| Granted                                         |       | 200,000                         |       |   | $ | 20.00 |   |   |
| Exercised                                       |       | —                          |       |   | — |   |   |
| Forfeited                                       |       | —                          |       |   | — |   |   |
| Outstanding, end  of period                     |       | 200,000                         |       |   | $ | 20.00 |   |   |
| Options  exercisable at end of period           |       | —                          |       |   | — |   |   |
| Weighted average fair  value of options granted |       |                            |       |   | $ | 1.44 |   |   |

 

*Restricted Units*

A restricted unit is a common unit that vests over aperiod of time and that during such time is subject to forfeiture. In addition,restricted units will vest upon a change in control of CE, unless providedotherwise by the compensation committee. Distributions made on restricted unitsmay be subjected to the same vesting provisions as the restricted units.

The restricted units are intended to serve as a meansof incentive compensation for performance and not primarily as an opportunityto participate in the equity appreciation of the common units. Therefore, 

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

**Note 10**—Member’s Capital(Continued)

plan participants will notpay any consideration for the common units they receive and CE will receive noremuneration for the units.

On December 13, 2004,CE awarded 3,000 restricted common units to each of its 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. The Company recognized expense of $13,000 related to the amortizationof these restricted units in 2004.

**Note 11**—RelatedParty Transactions

*Operations Services*

Through December 31, 2004, the Company did notdirectly employ any persons to manage or operate its business other thancertain Delaware-based officers. With respect to the Texas operating subsidiariesof the Company, Copano Operations provided management, operations andadministrative support services for the Company. The Company reimbursed CopanoOperations for all direct and indirect costs of these services. CopanoOperations charged these subsidiaries, without markup, based upon total monthlyexpenses incurred by Copano Operations less (i) a fixed allocation toreflect expenses incurred by Copano Operations for the benefit of certainentities controlled by Mr. Eckel and (ii) any costs to be chargeddirectly to an entity for which Copano Operations performed services. Managementbelieves that this methodology was reasonable. For the years ended December 31,2004, 2003 and 2002, the Company reimbursed Copano Operations $15,355,000,$12,190,000 and $9,329,000, respectively, for administrative and operatingcosts, including payroll and benefits expense for both field and administrativepersonnel of the Company. These costs are included in operations andmaintenance expenses and general and administrative expenses on theconsolidated statements of operations. As of December 31, 2004 and 2003,amounts payable by the Company to Copano Operations were $38,000 and$1,265,000, respectively.

Effective January 1, 2005 and pursuant to ageneral and administrative services agreement with Copano Operations, CopanoOperations transferred responsibility to CPNO Services, L.P., an indirectwholly owned subsidiary of CE, for a significant portion of the services,including its employment of certain employees on the Company’s behalf, thatCopano Operations had previously provided to the Company. Under the general andadministrative services agreement, the Company continues to reimburse CopanoOperations for all direct and indirect costs of the services provided to theCompany by Copano Operations using the same methodology as utilized prior to January 1,2005.

Management estimates thatthese expenses on a stand-alone basis (that is, the cost that would havebeen incurred by the Company to conduct current operations if the Company hadobtained these services from an unaffiliated entity) would not be significantlydifferent from the amounts recorded in the Company’s consolidated financialstatements for each of the three years in the period ended December 31,2004.

*Natural GasTransactions*

During the years ended December 31, 2004, 2003and 2002, the Company purchased natural gas from affiliated companies of Mr. Eckeltotaling $1,474,000, $1,896,000 and $1,117,000, respectively, and 

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

**Note 11**—RelatedParty Transactions (Continued)

provided gathering andcompression services to affiliated entities of Mr. Eckel totaling $75,000,$33,000 and $46,000, respectively. Additionally, affiliated companies of Mr. Eckelreimbursed the Company $53,000, $34,000 and $15,000 for the years ended December 31,2004, 2003 and 2002, respectively, in gas lift costs which are reflected as areduction of operations and maintenance expense in the consolidated statementsof operations. Management believes these purchases and sales were on terms noless favorable than those that could have been achieved with an unaffiliatedentity. As of December 31, 2004 and 2003, amounts payable by the Companyto affiliated companies of Mr. Eckel, other than Copano Operations,totaled $89,000 and $106,000, respectively.

The Company paid WDG fortransportation and purchased natural gas from WDG. Natural gas purchases andtransportation, net of natural gas sales to WDG, totaled $926,000, $665,000 and$1,312,000, for the years ended December 31, 2004, 2003 and 2002, respectively.Additionally, as operator of WDG, CWDPL charges WDG a monthly administrativefee of $16,000 and has made advances to WDG for capital expenditures. As of December 31,2004 and 2003, the Company’s net receivable from WDG totaled $1,141,000 and$651,000, respectively.

*Other*

A subsidiary of MerrillCorporation (“Merrill”), an affiliate of Credit Suisse First Boston PrivateEquity which held an interest in the Company as of December 31, 2004,provided the Company with printing and distribution services in connection withthe Offering and continues to provide assistance with printing and on-goingpublic filings. For the year ended December 31, 2004, the Company incurred$564,000 of printing, distribution and filing costs from Merrill, $559,000 ofwhich are recorded as Offering costs. Management believes that the Companyobtained these services on terms no less favorable than those that could havebeen achieved with an unaffiliated entity.

**Note 12**—CustomerInformation

The Company had three third-party customers thataccounted for 27% (Copano Pipelines/Copano Processing), 22% (Copano Processing)and 14% (Copano Processing) of its consolidated revenue in 2004. The Companyhad four third-party customers that accounted for 33% (Copano Pipelines/CopanoProcessing), 14% (Copano Pipelines), 9% (Copano Pipelines/Copano Processing)and 8% (Copano Pipelines) of its consolidated revenue in 2003. The Company hadthree third-party customers that accounted for 31% (CopanoPipelines/Copano Processing), 16% (Copano Pipelines) and 16% (CopanoProcessing) of its consolidated revenue in 2002. See Note 17 foradditional segment information.

The Company had two major suppliers in 2004 thataccounted for 11% and 8% of its consolidated cost of natural gas sold. The Companyhad two major suppliers in 2003 that accounted for 8% and 8% of itsconsolidated cost of natural gas sold. The Company had two major suppliers in2002 that accounted for 13% and 9% of its consolidated cost of natural gas sold.All of these major suppliers during the three years ended December 31,2004 sold volumes to the Copano Pipelines segment. See Note 17 foradditional segment information.

The Company had three third-party customers thataccounted for 31% (Copano Pipelines/Copano Processing), 29% (Copano Processing)and 11% (Copano Pipelines) of its consolidated accounts receivable as of December 31,2004. The Company had four third-party customers that accounted for 26% 

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

**Note 12**—CustomerInformation (Continued)

(CopanoPipelines/Copano Processing), 15% (Copano Pipelines), 13% (Copano Processing)and 12% (Copano Pipelines) of its consolidated accounts receivable as of December 31,2003. See Note 17 for additional segment information.

**Note 13**—RiskManagement Activities

From time to time, the Company may utilize a hedgingstrategy to mitigate the risk of the volatility of natural gas prices. For theyears ended December 31, 2004, 2003 and 2002, no such hedging positionswere purchased or exercised and no option positions were outstanding as of December 31,2004 or 2003.

TheCHC Credit Agreement and CPG Credit Agreement required both CHC and CPG toenter into interest rate risk management activities within 90 days of theestablishment of the facilities. In March 2002, CHC and CPG entered intointerest rate swap agreements with Fleet under the then existing creditfacilities. Amounts received or paid under these swaps were recorded asreductions or increases in interest expense. The table below summarizes theterms, amounts received or paid and the fair values of the various interestswaps:
| **Effective Date** | ** ** | **Expiration Date** | ** ** | **Notional  Amount** | ** ** | **Fixed  Rate** | ** ** | **Amounts  Paid in  2002** | ** ** | **Fair Value  December 31,  2002** | ** ** | **Amounts  Paid in  2003** | ** ** |
|-------------------------|------------|--------------------------|------------|----------------------|------------|-----------------|------------|---------------------------------|------------|----------------------------------------------|------------|---------------------------------|------------|
| March 1,  2002     |       | March 1,  2003      |       | $                    | 15,000,000 |            | 2.57       | %                               | $          | 80,209                                       |       |                            | $          | (43,391 | ) |   | $ | 43,391 |   |
| March 1,  2002     |       | September 1,  2003  |       | 5,000,000            |       | 3.03            | %          | 44,370                          |       |                                         | (60,832    | )                               |       | 64,014 |   |
| March 1, 2002      |       | September 1,2003    |       | 10,000,000           |       | 3.03            | %          | 88,740                          |       |                                         | (121,665   | )                               |       | 128,028 |   |
|                         |            |                          |            |                      |            |                 |            |                                 |            |                                              |            |                                 |            |  |  |  |  |  |  |

 

As of December 31,2004 and 2003, no such interest rate swap contracts were outstanding.

**Note 14**—FairValue of Financial Instruments

The carrying amount of cash equivalents is believed toapproximate their fair values because of the short maturities of theseinstruments. As of December 31, 2004 and 2003, the debt associated withthe CPG Credit Agreement, the CHC Facility and the CHC Credit Agreement (repaidin February 2004) bore interest at floating rates. As such, carryingamounts of these debt instruments approximate fair values.

The debt associated withthe Tejas Credit Agreement (repaid in November 2004) had a fixed rate of14%. As of December 31, 2003, management believed that the carrying amountof the subordinated debt approximated its fair value.

**Note 15**—Commitmentsand Contingencies

*Commitments*

For the years ended December 31,2004, 2003 and 2002, rental expense for office space, leased vehicles andleased compressors and related field equipment used in the Company’s operationstotaled $1,598,000, $1,631,000 and $1,066,000, respectively. As of December 31,2004, commitments under the Company’s lease obligations for the next five yearsand thereafter are payable as follows: *2005*—$670,000; *2006*—$454,000; *2007*—$350,000; *2008*—$344,000; *2009*—$344,000;and *thereafter*—$143,000. During 2003,certain CE subsidiaries became co-lessors of office space with CopanoOperations.

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

**Note 15**—Commitmentsand Contingencies (Continued)

The Company has both fixedand variable contractual commitments arising in the ordinary course of itsnatural gas marketing activities. As of December 31, 2004, the Company hadfixed contractual commitments to purchase 364,250 million British thermalunits (“MMBtu”) of natural gas in January 2005. As of December 31,2004, the Company had fixed contractual commitments to sell2,461,400 MMBtu of natural gas in January 2005 and 295,000 MMBtuof natural gas between February 2005 and March 2005. All of thesecontracts are based on index-related market pricing. Using index-relatedmarket prices as of December 31, 2004, total commitments to purchasenatural gas related to such agreements equaled $2,086,000 and the totalcommitment to sell natural gas under such agreements equaled $13,826,000. TheCompany’s commitments to purchase variable quantities of natural gas at index-basedprices range from contract periods extending from one month to the life of thededicated production. During December 2004, natural gas volumes purchasedunder such contracts equaled 4,591,203 MMBtu. The Company’s commitments tosell variable quantities of natural gas at index-based prices range fromcontract periods extending from one month to 2012. During December 2004,natural gas volumes sold under such contracts equaled 565,440 MMBtu.

*Guarantees*

In November 2002, the FASB issued Interpretation No.(“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of Indebtedness of Others.” Incertain instances, this interpretation requires a guarantor to recognize, atthe inception of a guarantee, a liability for the fair value of the obligationundertaken in issuing the guarantee.

From July 8,2002 through April 1, 2004, the Company guaranteed certain vehicle leaseobligations of Copano Operations for vehicles operated for the benefit ofcertain of Copano operating entities. Effective as of April 2, 2004, thevehicle leases were transferred by Copano Operations to Hebbronville andHebbronville, as lessee, guarantees the lessor a minimum residual sales valueupon the expiration of the lease and sale of the underlying vehicle. Certain ofthe Copano Pipelines entities currently guarantee the lease paymentobligations, including the residual sales value. As of December 31, 2004,the Company guaranteed $170,000 related to these lease payment obligations. Asof December 31, 2004, aggregate guaranteed residual values for vehiclesunder these operating leases were as follows (in thousands):
| ** **             | ** ** | **2005** | ** ** | ** 2006 ** | ** ** | ** 2007 ** | ** ** | **2008** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------|------------|----------|------------|----------------------|------------|----------------------|------------|----------|------------|----------------|------------|-----------|------------|
| Lease residual  values |       | $        | 176        |                 |       | $                    | 36         |     |       |           | $          | 55        |       |   | $ | — |   |   | $ | — |   |   | $ | 267 |   |
|                        |            |          |            |                      |            |                      |            |          |            |                |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

Effective April 12, 2003, the Company hasguaranteed certain telephone equipment lease obligations (approximately $21,600of lease payment obligations as of December 31, 2004) of Copano Operations.The use of this telephone equipment by the Company is included in the supportservices provided by Copano Operations to the Company. See Note 11.

Presently, neither the Company nor any of itssubsidiaries have any other types of guarantees outstanding that requireliability recognition under the provisions of FIN 45.

FIN 45 also sets forth disclosure requirements for guaranteesby a parent company on behalf of its subsidiaries. CE or a subsidiary entity,from time to time, may issue parent guarantees of commitments resulting fromthe ongoing activities of subsidiary entities. Additionally, a subsidiaryentity may from time to time issue a guarantee of commitments resulting fromthe ongoing activities of another subsidiary entity.

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

**Note 15**—Commitmentsand Contingencies (Continued)

The guaranteesgenerally arise in connection with a subsidiary commodity purchase obligation,subsidiary lease commitments and subsidiary bank debt. The nature of suchguarantees is to guarantee the performance of the subsidiary entities inmeeting their respective underlying obligations. Except for operating leasecommitments, all such underlying obligations are recorded on the books of thesubsidiary entities and are included in the 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 31,2004, the approximate amount of parental guaranteed obligations were as follows(in thousands):
| ** **           | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **Total** | ** ** |
|----------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|-----------|------------|
| Bank debt            |       | $        | —     |     | $          | —   |       | $        | 9,000      |      | $          | 48,000 |   | $ | 57,000 |   |
| Commodity  purchases |       | 5,400    |       | —   |       | —   |       | —   |       | 5,400     |       |
|                 |       | $        | 5,400      |     | $          | —   |       | $        | 9,000      |      | $          | 48,000 |   | $ | 62,400 |   |

 

*RegulatoryCompliance*

In the ordinary course ofbusiness, the Company 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 Company.

*Litigation*

The Company is named as adefendant, from time to time, in litigation relating to its normal businessoperations. Management is not aware of any significant litigation, pending orthreatened, that would have a significant adverse effect on the Company’sfinancial position or results of operations.

**Note 16**—SupplementalDisclosures to the Statements of Cash Flows

*Cash paid during each of the periods presented (inthousands)*
| ** ** | ** ** | **Year Ended December 31,** | ** ** |
|------------|------------|--------------------------------------------|------------|
| ** ** | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| Interest   |       | $                                          | 3,891      |   | $ | 1,611 |   | $ | 2,251 |   |
| Taxes      |       | —                                     |       | 28 |   | — |   |
|            |            |                                            |            |  |  |  |  |  |  |  |

 

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

**Note 16**—SupplementalDisclosures to the Statements of Cash Flows (Continued)

*Supplemental disclosures of noncash investing andfinancing activities (in thousands)*
| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                        | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| Issuance of  subordinated notes                                                   |       | $                                          | —     |   | $ | 850 |   | $ | — |   |
| Decrease in other  current liabilities                                            |       | —                                     |       | (850 | ) | — |   |
| Increase of  redeemable preferred units related to the issuance of PIK units |       | —                                     |       | 2,453 |   | 3,853 |   |
| Decrease in  members’ capital related to the issuance of PIK units           |       | —                                     |       | (2,453 | ) | (3,853 | ) |
| Increase of  redeemable preferred units related to the accretion of warrant value |       | —                                     |       | 743 |   | 1,379 |   |
| Decrease in  members’ capital related to the accretion of warrant value      |       | —                                     |       | (743 | ) | (1,379 | ) |
| (Decrease) increase  other comprehensive income (loss)                            |       | —                                     |       | 226 |   | (226 | ) |
| Increase  (decrease) other current liabilities                                    |       | —                                     |       | (226 | ) | 226 |   |
| Increase in  members’ capital                                                |       | —                                     |       | 1,258 |   | — |   |
| Decrease of  redeemable preferred units                                           |       | —                                     |       | (1,258 | ) | — |   |
| Increase in  equity in loss from unconsolidated affiliate                         |       | 120                                        |       | 120 |   | 110 |   |
| Decrease in  accounts receivable from affiliates                                  |       | (120                                       | )          | (120 | ) | (110 | ) |
| Increase in  property, plant and equipment                                        |       | (890                                       | )          | — |   | — |   |
| Increase in other  noncurrent liabilities                                         |       | 890                                        |       | — |   | — |   |
|                                                                                   |            |                                            |            |  |  |  |  |  |  |  |

 

**Note 17**—SegmentInformation

Based on its management’sapproach, the Company believes its operations consist of two segments: (i) gathering,transportation and marketing of natural gas (Copano Pipelines) and (ii) naturalgas processing and related NGL transportation (Copano Processing). The Companycurrently reports its operations, both internally and externally, using thesetwo segments. The Company evaluates segment performance based on segment marginbefore depreciation and amortization. All of the Company’s revenue is derivedfrom, and all of the Company assets and operations are located in, the SouthTexas and Texas Gulf Coast regions of the United States. Transactions betweenreportable segments are conducted on an arm’s length basis.

F-34

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

**Note 17**—SegmentInformation (Continued)

Summarized financialinformation concerning the Company’s reportable segments is shown in thefollowing table (in thousands):
| ** **                                   | ** ** | **Copano  Pipelines** | ** ** | **Copano  Processing** | ** ** | **Corporate** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|----------------------------------------------|------------|-----------------------|------------|------------------------|------------|---------------|------------|------------------|------------|-----------|------------|
| ***Year  Ended December 31, 2004:***    |       |                  |       |                   |       |          |       |             |       |      |       |
| Sales to external customers                  |       | $                     | 274,595    |                   | $          | 163,061       |       | $                | —     |      | $          | — |   | $ | 437,656 |   |
| Intersegment sales                           |       | 146,812               |       | 18,442                 |       | —        |       | (165,254         | )          | —    |       |
| Interest expense 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 expense 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    | )          |
| Segment assets                               |       | 148,872               |       | 98,511                 |       | 2,098         |       | (87,772          | )          | 161,709   |       |
| Capital expenditures                         |       | 3,727                 |       | 2,465                  |       | —        |       | —           |       | 6,192     |       |
| ***Year  Ended December 31, 2002:***    |       |                  |       |                   |       |          |       |             |       |      |       |
| Sales to external customers                  |       | $                     | 111,400    |                   | $          | 113,496       |       | $                | —     |      | $          | — |   | $ | 224,896 |   |
| Intersegment sales                           |       | 121,330               |       | 21,237                 |       | —        |       | (142,567         | )          | —    |       |
| Interest expense and other financing costs   |       | 2,481                 |       | 3,879                  |       | —        |       | —           |       | 6,360     |       |
| Depreciation and amortization                |       | 3,989                 |       | 1,547                  |       | 3             |       | —           |       | 5,539     |       |
| Equity in loss from unconsolidated affiliate |       | 584                   |       | —                 |       | —        |       | —           |       | 584       |       |
| Segment profit (loss)                        |       | 4,294                 |       | (5,704                 | )          | (231          | )          | —           |       | (1,641    | )          |
| Segment assets                               |       | 122,532               |       | 94,649                 |       | 402           |       | (58,062          | )          | 159,521   |       |
| Capital  expenditures                        |       | 8,491                 |       | 4,547                  |       | 66            |       | —           |       | 13,104    |       |

 

**Note 18**—QuarterlyFinancial Data (Unaudited)
| ** **                          | ** ** | **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 | ) |
|                                     |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

F-35

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

**Note 18**—QuarterlyFinancial Data (Unaudited) (Continued)
| ** **                          | ** ** | **Year  2003**          | ** ** |
|-------------------------------------|------------|-------------------------|------------|
| ** **                          | ** ** | **Quarter Ended**  | ** ** | ** ** | ** ** |
| ** **                          | ** ** | **March 31**       | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** | **Year** | ** ** |
| ** **                          | ** ** | **(In thousands)** | ** ** |
| Revenue                             |       | $                       | 112,130    |   | $ | 90,250 |   |   | $ | 92,931 |   |   |   | $ | 89,260 |   |   | $ | 384,571 |   |
| Operating income                    |       | 5,409                   |       | (2,000 | ) |   | 230 |   |   |   | 3,709 |   |   | 7,348 |   |
| Net income (loss)                   |       | 3,741                   |       | (3,597 | ) |   | (3,574 | ) |   |   | (1,287 | ) |   | (4,717 | ) |
| Basic net income  (loss) per unit   |       | 1.29                    |       | (3.93 | ) |   | (2.51 | ) |   |   | (0.09 | ) |   | (6.21 | ) |
| Diluted net income  (loss) per unit |       | 0.78                    |       | (3.93 | ) |   | (2.51 | ) |   |   | (0.09 | ) |   | (6.21 | ) |
|                                     |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

 

F-36

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

To the Operating GeneralPartner 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 and for the period from February 1, 2002through December 31, 2002. These financial statements are theresponsibility of the Partnership’s management. Our responsibility is toexpress an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standardsof 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. The Partnership is not required to have, nor were we engaged toperform, an audit of its internal control over financial reporting. Our auditincluded consideration of internal control over financial reporting as a basisfor designing audit procedures that are appropriate in the circumstances, butnot for the purpose of expressing an opinion on the effectiveness of theCompany’s internal control over financial reporting. Accordingly, we express nosuch opinion. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements, assessing theaccounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation. We believethat our audits provide a reasonable basis for our opinion.

In ouropinion, such financial statements present fairly, in all material respects,the financial position of the Partnership at December 31, 2004, and theresults of its operations and its cash flows for the year ended December 31,2004 and for the period from February 1, 2002 through December 31,2002 in conformity with accounting principles generally accepted in the UnitedStates of America.
| /s/ Deloitte & Touche LLP |
|------------------------------------|
| Houston, Texas                     |
| March 29, 2005                |

 

F-37

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**WEBB/DUVALGATHERERSBALANCE SHEETS**
| ** **                                    | ** ** | **December 31,** | ** ** |
|-----------------------------------------------|------------|-----------------------|------------|
| ** **                                    | ** ** | **2004**              | ** ** | **2003** | ** ** |
| ** **                                    | ** ** | ** **            | ** ** | **(unaudited)** | ** ** |
| **Assets**                                    |       |                  |       |   |   |
| Current assets:                               |       |                  |       |   |   |
| Cash and cash equivalents                     |       | $                     | 114,495    |   | $ | 321,213 |   |
| Accounts receivable                           |       | 2,174,378             |       | 2,651,159 |   |
| Accounts receivable from affiliates           |       | 42,162                |       | 83,866 |   |
| Prepayments and other current assets          |       | 17,194                |       | 18,813 |   |
| Total current assets                          |       | 2,348,229             |       | 3,075,051 |   |
| Property and equipment, net                   |       | 8,283,335             |       | 8,525,798 |   |
| Total assets                                  |       | $                     | 10,631,564 |   | $ | 11,600,849 |   |
| **Liabilities  and Partners’ Capital**   |       |                  |       |   |   |
| Current liabilities:                          |       |                  |       |   |   |
| Accounts payable                              |       | $                     | 1,340,194  |   | $ | 3,032,741 |   |
| Accounts payable to affiliates                |       | 1,897,250             |       | 1,584,908 |   |
| Other current liabilities                     |       | —                |       | 35,380 |   |
| Total current liabilities                     |       | 3,237,444             |       | 4,653,029 |   |
| Commitments and  contingencies (Note 9)       |       |                  |       |   |   |
| Total partners’  capital                 |       | 7,394,120             |       | 6,947,820 |   |
| Total liabilities  and partners’ capital |       | $                     | 10,631,564 |   | $ | 11,600,849 |   |

 

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

F-38

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**WEBB/DUVALGATHERERSSTATEMENTS OF OPERATIONS**
| ** **                                        | ** ** | **Year Ended December 31,** | ** ** | **Period From  February 1,  2002 through  December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|------------------------------------------------------------------------------|------------|
| ** **                                        | ** ** | **2004**                                   | ** ** | **2003**                                                                     | ** ** | **2002** | ** ** |
| ** **                                        | ** ** | ** **                                 | ** ** | **(unaudited)**                                                              | ** ** | ** ** | ** ** |
| Revenue:                                          |       |                                       |       |                                                                         |       |   |   |
| Natural gas sales                                 |       | $                                          | 330,919    |                                                                         | $          | 475,428 |   | $ | 84,093 |   |
| Natural gas sales to affiliates                   |       | 2,144,428                                  |       | 954,165                                                                      |       | 1,220,498 |   |
| Transportation and gathering fees                 |       | 1,018,399                                  |       | 1,040,478                                                                    |       | 184,351 |   |
| Transportation and gathering fees from affiliates |       | 640,812                                    |       | 285,498                                                                      |       | 768,057 |   |
| Condensate sales                                  |       | 421,169                                    |       | 424,279                                                                      |       | 178,833 |   |
| Other                                             |       | 26,264                                     |       | —                                                                       |       | — |   |
| Other—affiliate                              |       | 23,000                                     |       | —                                                                       |       | — |   |
| Total revenue                                     |       | 4,604,991                                  |       | 3,179,848                                                                    |       | 2,435,832 |   |
| Costs and  expenses:                              |       |                                       |       |                                                                         |       |   |   |
| Cost of natural gas sold                          |       | 575,735                                    |       | 960,607                                                                      |       | 2,199,403 |   |
| Cost of natural gas—affiliates               |       | 1,642,916                                  |       | 907,799                                                                      |       | 60,220 |   |
| Operations and maintenance                        |       | 853,057                                    |       | 711,537                                                                      |       | 407,306 |   |
| Depreciation and amortization                     |       | 654,929                                    |       | 591,215                                                                      |       | 525,686 |   |
| General and administrative                        |       | 315,536                                    |       | 275,494                                                                      |       | 243,140 |   |
| Taxes other than income                           |       | 116,518                                    |       | 160,942                                                                      |       | 140,967 |   |
| Total cost and expenses                           |       | 4,158,691                                  |       | 3,607,594                                                                    |       | 3,576,722 |   |
| Net income (loss)                                 |       | $                                          | 446,300    |                                                                         | $          | (427,746 | ) | $ | (1,140,890 | ) |

 

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

F-39

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**WEBB/DUVALGATHERERSSTATEMENTS OF CASH FLOWS**
| ** **                                                                                | ** ** | **Year Ended December 31,** | ** ** | **Period From  February 1,  2002 through  December 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|------------------------------------------------------------------------------|------------|
| ** **                                                                                | ** ** | **2004**                                   | ** ** | **2003**                                                                     | ** ** | **2002** | ** ** |
| ** **                                                                                | ** ** | ** **                                 | ** ** | **(unaudited)**                                                              | ** ** | ** ** | ** ** |
| Cash Flows From  Operating Activities:                                                    |       |                                       |       |                                                                         |       |   |   |
| Net income (loss)                                                                         |       | $                                          | 446,300    |                                                                         | $          | (427,746 | ) | $ | (1,140,890 | ) |
| Adjustments to  reconcile net income (loss) to net cash provided by operating activities: |       |                                       |       |                                                                         |       |   |   |
| Depreciation and amortization                                                             |       | 654,929                                    |       | 591,215                                                                      |       | 525,686 |   |
| (Increase)  decrease in:                                                                  |       |                                       |       |                                                                         |       |   |   |
| Accounts receivable                                                                       |       | 476,781                                    |       | (1,118,049                                                                   | )          | 66,150 |   |
| Accounts receivable from affiliates                                                       |       | 41,704                                     |       | 194,212                                                                      |       | (278,078 | ) |
| Prepayments and other current assets                                                      |       | 1,619                                      |       | (107                                                                         | )          | (18,706 | ) |
| Increase  (decrease) in:                                                                  |       |                                       |       |                                                                         |       |   |   |
| Accounts payable                                                                          |       | (1,692,547                                 | )          | 643,979                                                                      |       | 753,491 |   |
| Accounts payable to affiliates                                                            |       | 312,342                                    |       | 868,308                                                                      |       | 716,600 |   |
| Other current liabilities                                                                 |       | (35,380                                    | )          | 33,048                                                                       |       | 2,332 |   |
| Net cash provided by operating activities                                                 |       | 205,748                                    |       | 784,860                                                                      |       | 626,585 |   |
| Cash Flows From  Investing Activities:                                                    |       |                                       |       |                                                                         |       |   |   |
| Additions to property and equipment                                                       |       | (412,466                                   | )          | (542,063                                                                     | )          | (548,169 | ) |
| Net cash used in investing activities                                                     |       | (412,466                                   | )          | (542,063                                                                     | )          | (548,169 | ) |
| Cash Flows From  Financing Activities:                                                    |       | —                                     |       | —                                                                       |       | — |   |
| Net (decrease) increase in cash and cash equivalents                                      |       | (206,718                                   | )          | 242,797                                                                      |       | 78,416 |   |
| Cash and cash  equivalents, beginning of period                                           |       | 321,213                                    |       | 78,416                                                                       |       | — |   |
| Cash and cash  equivalents, end of year                                                   |       | $                                          | 114,495    |                                                                         | $          | 321,213 |   | $ | 78,416 |   |

 

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

F-40

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**WEBB/DUVALGATHERERSSTATEMENTS OF PARTNERS’ CAPITAL**
| Balance,  February 1, 2002              |   | $          | 8,516,456 |   |
|----------------------------------------------|--------|------------|-----------|--------|
| Net loss                                     |   | (1,140,890 | )         |
| 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 |   |

 

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

F-41

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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. InFebruary 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”) (formerly Copano Energy Holdings, L.L.C.), increased itsownership interest in the Partnership from a 15% general partnership interestto a 62.5% general partnership interest. As a result of CWDPL’s acquisition ofthis additional 47.5% general partnership interest in the Partnership, CWDPLassumed operations of the Partnership from the previous operator onFebruary 1, 2002. The remaining partners, that have substantiveparticipating rights with respect to the management of the Partnership,collectively own a 37.5% general partnership interest in the Partnership.

The accompanying financialstatements include the assets, liabilities and results of operations of thePartnership as of December 31, 2004 and 2003 and for the year endedDecember 31, 2004 and 2003 and for the period from February 1, 2002through December 31, 2002. A full year presentation is not practicable for2002 because, as discussed above, CWDPL only became the operator of thePartnership on February 1, 2002.

**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.

F-42

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*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. In evaluating the level of established reserves, thePartnership makes judgments regarding each party’s ability to make requiredpayments, economic events and other factors. As the financial condition of anyparty changes, circumstances develop, or additional information becomesavailable, adjustments to the allowance for doubtful accounts may be required. Managementof the Partnership has established various procedures to manage its creditexposure, including initial credit approvals, credit limits and rights ofoffset. The Partnership may also use prepayments and guarantees to limit creditrisk to ensure that management’s established credit criteria are met. As ofDecember 31, 2004 and 2003, the Partnership has not established anallowance for doubtful accounts.

*Property andEquipment*

Property and equipment consist of gas gathering systemsand 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 30-year estimateduseful lives of the Partnership’s assets. The weighted average useful life ofthe Partnership’s pipeline and equipment assets is approximately 15 years.

The Partnership reviewslong-lived assets for impairment whenever there is evidence that the carryingvalue of such assets may not be recoverable. This review consists of comparingthe carrying value of the asset with the asset’s expected future undiscountedcash flows 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 management’s best estimate based onreasonable and supportable assumptions.

*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 receipt or delivery ofnatural gas in future periods, if not subject to cash out provisions. Imbalancereceivables are included in accounts receivable and accounts receivable from affiliatesand imbalance payables are included in accounts payable and accounts payable toaffiliates on the balance sheets and are valued at estimated settlement pricesor marked-to-market using current market prices in effect for the reportingperiod of the outstanding imbalances. As of December 31, 2004 and 2003,the Partnership had imbalance receivables totaling $1,850,697 and $2,202,902(unaudited), respectively, and imbalance payables totaling $2,003,253 and$3,464,856 (unaudited), respectively. Changes in market value and thesettlement of any such imbalance at a price greater than or less than therecorded imbalance results in either an upward or downward adjustment, asappropriate, to the cost of natural gas sold.

F-43

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*Asset RetirementObligation*

In June 2001, the Financial Accounting StandardsBoard (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143,“Accounting for Asset Retirement Obligations.” This statement requires entitiesto record the fair value of a liability for legal obligations associated withthe retirement obligations of tangible long-lived assets in the period in whichthe obligation is incurred and can be reasonably estimated. When the liabilityis initially recorded, a corresponding increase in the carrying amount of therelated long-lived asset is recorded. Over time, accretion of the liability isrecognized each period, and the capitalized cost is depreciated over the usefullife of the related asset. Upon settlement of the liability, an entity eithersettles the obligation for its recorded amount or incurs a gain or loss onsettlement. The standard became effective for the Partnership onJanuary 1, 2003.

Under the implementation guidelines of SFAS No. 143,the Partnership has reviewed its long-lived assets for asset retirementobligation (“ARO”) liabilities and identified any such liabilities. Theseliabilities include ARO liabilities 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.

As a result of thePartnership’s analysis of AROs, the Partnership determined it was not requiredto recognize any such potential liabilities. The Partnership’s rights under itseasements are renewable or perpetual and retirement action, if any, is requiredonly upon nonrenewal or abandonment of the easements. The Partnership currentlyexpects to continue to use or renew all such easement agreements and to usethese properties for the foreseeable future. Accordingly, management is unableto reasonably estimate and record liabilities for its obligations that fallunder the provisions of SFAS No. 143 because it does not believe that any ofthe applicable assets will be retired or abandoned in the foreseeable future. ThePartnership will record AROs in the period in which the obligation may bereasonably estimated.

*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, as amended, “Accountingfor Derivative Instruments and Hedging Activities,” establishes accounting andreporting standards for derivative instruments, including certain derivativeinstruments embedded in other contracts, and for hedging activities. SFAS No. 133requires that an entity recognize all derivatives as either assets orliabilities in the statement of financial position and measure thoseinstruments at fair value. 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. The Partnership’sforward natural gas purchase and sales contracts are designated as normalpurchases and sales. Substantially all forward contracts fall within aone-month to five-year term.

F-44

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 2**—Summaryof Significant Accounting Policies (Continued)

*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

In December 2004, theFASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets an amendment of APBOpinion No. 29.” This statement amends Accounting Principles Board OpinionNo. 29 to eliminate the exception for nonmonetary exchanges of similarproductive assets and replaces it with a general exception for exchanges ofnonmonetary assets that do not have commercial substance. The statementspecifies that a nonmonetary exchange has commercial substance if the futurecash flows of the entity are expected to change significantly as a result ofthe exchange. This statement is effective for nonmonetary asset exchangesoccurring in fiscal periods beginning after June 15, 2005. Earlier applicationis permitted for nonmonetary asset exchanges occurring in fiscal periodsbeginning after the date this statement is issued. Retroactive application isnot permitted. Management is analyzing the requirements of this new statementand believes that its adoption will not have any significant impact on the Partnership’sfinancial position, results of operations or cash flows.

**Note 4**—Propertyand Equipment

Property and equipmentconsisted of the following:
| ** **                                      | ** ** | **December 31,** | ** ** |
|-------------------------------------------------|------------|-----------------------|------------|
| ** **                                      | ** ** | **2004**              | ** ** | **2003** | ** ** |
| ** **                                      | ** ** | ** **            | ** ** | **(unaudited)** | ** ** |
| Property and equipment,  at cost:               |       |                  |       |   |   |
| Pipelines and equipment                         |       | $                     | 25,143,074 |   | $ | 24,777,023 |   |
| Construction in progress                        |       | 60,625                |       | 16,009 |   |
|                                            |       | 25,203,699            |       | 24,793,032 |   |
| Less accumulated  depreciation and amortization |       | (16,920,364           | )          | (16,267,234 | ) |
| Total property  and equipment, net              |       | $                     | 8,283,335  |   | $ | 8,525,798 |   |

 

**Note 5**—RiskManagement Activities

The Partnership mayutilize a hedging strategy to mitigate the risk of the volatility of naturalgas prices in connection with the purchase or sale of natural gas with respectto the resolution of its natural gas imbalance positions. However, for the yearsended December 31, 2004 and 2003 (unaudited) and for the period fromFebruary 1, 2002 through December 31, 2002, no such hedging positionswere purchased or exercised and no option positions were outstanding as ofDecember 31, 2004 or 2003 (unaudited).

F-45

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 6**—RelatedParty 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. John R. Eckel, Jr., Chairmanof the Board of Directors and Chief Executive Officer of CE, provided these managementand operations support services as well as administrative support services toCWDPL, the operator of the Partnership. Effective January 1, 2005, CopanoOperations transferred responsibility to CPNO Services, L.P., an indirectwholly owned subsidiary of CE, for a significant portion of the services thatCopano Operations had previously provided to CWDPL. CWDPL reimburses CopanoOperations for all direct and indirect costs of services provided by CopanoOperations. CWDPL charges the Partnership for operations and support servicesas well as a monthly administrative fee of $16,000 and is reimbursed by thePartnership for certain personnel services not included in the administrativefee. Additionally, CWDPL has made advances to WDG for capital expenditures. Forthe years ended December 31, 2004 and 2003 and for the period fromFebruary 1, 2002 through December 31, 2002, CWDPL charged thePartnership $711,593, $619,743 (unaudited) and $478,004, respectively, foradministrative fees and operations and support services including payroll andbenefits expense for both field and administrative personnel of the Partnershipand capitalized costs. As of December 31, 2004 and 2003, the Partnership’snet payable to CWDPL totaled $940,928 and $718,217 (unaudited), 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, 2004 and 2003 and for the periodfrom February 1, 2002 through December 31, 2002.

*Natural GasTransportation and Exchange Imbalance Transactions*

Pursuant to a gas gathering agreement, the Partnershipearned transportation fees of $492,590, $180,928 (unaudited) and $91,274 fromCopano Field Services/Agua Dulce (“CFS/AD”), an indirect wholly ownedsubsidiary of CE and an affiliate of CWDPL, during the years endedDecember 31, 2004 and 2003 and for the period from February 1, 2002 throughDecember 31, 2002, respectively. The Partnership recorded natural gassales of $1,330,993, $913,332 (unaudited) and $1,220,498 pursuant to theimbalance cash out provisions of the gas gathering agreement with CFS/AD duringthe years ended December 31, 2004 and 2003 and for the period fromFebruary 1, 2002 through December 31, 2002, respectively. Additionally,the Partnership recorded cost of natural gas sold of $1,135,402, $459,860(unaudited) and $0 pursuant to the cash out provisions of the gas gatheringagreement with CFS/AD for the years ended December 31, 2004 and 2003 andfor the period from February 1, 2002 through December 31, 2002,respectively. As of December 31, 2004, the Partnership owed CFS/AD $200,406under this gas gathering agreement and as of December 31, 2003, CFS/ADowed the Partnership $53,190 (unaudited) under this gas gathering agreement.

Pursuant to gas purchase and sales agreements, thePartnership sold natural gas to other affiliates of CWDPL and indirect whollyowned subsidiaries of CE of $787,117 and $40,833 (unaudited) and $0 during theyears ended December 31, 2004 and 2003 and for the period fromFebruary 1, 2002 through December 31, 2002, respectively. Additionally,the Partnership recorded cost of natural gas sold to these other affiliates ofCWDPL of $550,733, $9,571 (unaudited) and $0 during the years endedDecember 31, 

F-46

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 6**—RelatedParty Transactions (Continued)

2004 and 2003 and for theperiod from February 1, 2002 through December 31, 2002, respectively.The Partnership also earned transportation fees from these other affiliates ofCWDPL of $1,575, $0 (unaudited) and $0 during the years ended December 31,2004 and 2003 and for the period from February 1, 2002 throughDecember 31, 2002, respectively.

Pursuant to gas gathering agreements with the othergeneral partners of the Partnership, the Partnership earned transportation feesof $146,647 and $104,570 (unaudited) and $93,077 during the years endedDecember 31, 2004 and 2003 and for period from February 1, 2002through December 31, 2002, respectively. Additionally, under one of theother general partner’s gas gathering agreement, the Partnership recorded gasimbalance activity as cost of natural gas sold of $(111,288), $438,368(unaudited) and $60,220 during the years ended December 31, 2004 and 2003 andfor the period from February 1, 2002 through December 31, 2002,respectively. Under one of the other general partner’s gas gathering agreement,the Partnership had net purchases of natural gas of $41,752, $0 (unaudited) and$0 during the years ended December 31, 2004 and 2003 and for the periodfrom February 1, 2002 through December 31, 2002, respectively. As ofDecember 31, 2004 and 2003, these general partners owed the Partnership $41,973and $16,745 (unaudited), respectively, for transportation fees. Additionallyone of these general partners paid a well connection fee of $23,000 during theyear ended December 31, 2004. The Partnership had net gas imbalance obligationsto these general partners of $755,915 and $866,691 (unaudited) as ofDecember 31, 2004 and 2003, 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 had twoaffiliated customers and one third-party customer 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 endedDecember 31, 2003. The Partnership had one affiliated customer and onethird-party customer that accounted for 54% and 17%, respectively, of itsrevenue for the period from February 1, 2002 through December 31,2002.

Excluding changes in thegas imbalances recorded as cost of natural gas sold, the Partnership had one third-partyand two affiliated suppliers during the year ended December 31, 2004 thataccounted for 38%, 34% and 17%, respectively, of its cost of natural gas sold. Excludingchanges in the gas imbalances recorded as cost of natural gas sold, thePartnership had one (unaudited) third-party supplier and one (unaudited) affiliatedsupplier for the year ended December 31, 2003 that accounted for 78%(unaudited) and 21% (unaudited), respectively, of its cost of natural gas sold.Excluding changes in the gas imbalances recorded as cost of natural gas sold,the Partnership had one third-party supplier during the period fromFebruary 1, 2002 through December 31, 2002 that accounted for 100% ofits cost of natural gas sold. The Partnership only buys and sells natural gasin connection with the resolution of natural gas imbalances incurred as aresult of its gathering and transportation activities.

F-47

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**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, 2004 and 2003and for the period from February 1, 2002 through December 31, 2002,rental expense for leased vehicles and leased compressors and related fieldequipment used in the Partnership’s operations totaled $180,269, $186,950(unaudited) and $67,608. As of December 31, 2004, commitments under thePartnership’s lease obligations totaled $13,704 for 2005, $8,394 for 2006 and$700 for 2007.

Although the Partnershipmay have both fixed and variable contractual commitments arising in theordinary course of its activities, as of December 31, 2004, thePartnership had no fixed or variable contractual commitments to purchase orsell natural gas.

*Guarantees*

In November 2002, the FASB issued InterpretationNo (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements forGuarantees, Including Indirect Guarantees of Indebtedness of Others.” Incertain instances, this interpretation requires a guarantor to recognize, atthe inception of a guarantee, a liability for the fair value of the obligationundertaken 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. As ofDecember 31, 2004, no parental guarantees by the general partners areoutstanding. However, from July 8, 2002 through April 1, 2004,subsidiaries of CE guaranteed certain vehicle lease obligations of CopanoOperations for vehicles operated for the benefit of the Partnership and certainsubsidiaries of CE. Effective April 2, 2004, the vehicle lease was transferredto a subsidiary of CE, as lessee. As of December 31, 2004, certain other subsidiariesof CE guaranteed approximately $170,000 of the lessee’s lease paymentobligations (approximately $22,798 relates to vehicles used by the Partnership).Additionally, under each vehicle lease, the lessee has guaranteed the lessor aminimum residual sales value upon the expiration of the lease and sale of theunderlying vehicle. These residual sale values guaranteed by the lessee are inturn guaranteed by certain other subsidiaries of CE. At December 31, 2004,guaranteed residual values for vehicles used by the Partnership under theseoperating leases were as follows:
| ** **             | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Lease residual  values |       | $        | 43,418     |     | $          | —   |       | $        | 13,654     |           | $          | —    |       |   | $ | — |   |   | $ | 57,072 |   |
|                        |            |          |            |          |            |          |            |          |            |                |            |           |            |  |  |  |  |  |  |  |  |

 

Presently, neither thePartnership nor any of its general partners have any other types of guarantees outstandingthat 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.

F-48

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**WEBB/DUVAL GATHERERS NOTES TO FINANCIAL STATEMENTS—(Continued)**

**Note 9**—Commitmentsand Contingencies (Continued)

*Litigation*

The Partnership may be named as a defendant, from timeto time, in litigation relating to its normal business operations. Managementis not aware of any significant litigation, pending or threatened, that wouldhave a significant adverse effect on the Partnership’s financial position orresults of operations.

F-49

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**Exhibit Index**
| 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 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).                        |
| 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/Lice 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

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| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.11*     |   | Second Amendment to  Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the  Copano Controlling Entities, effective March 1, 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.14*     |   | First Amendment to  Employment Agreement between CPNO Services, L.P. and James J.  Gibson, III, effective March 1, 2005.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.15      |   | Lease Agreement dated  August 14, 2003 between Mateo Lueia and Copano Field Services/Agua  Dulce, L.P. (incorporated by reference to Exhibit 10.11 to Amendment  No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 10.16      |   | Lease Agreement dated  January 22, 2003 between Copano/Operations, Inc., Copano  Processing, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano  Pipelines/Hebbronville, L.P. and Copano Field Services/Central Gulf Coast,  L.P. and American General Life Insurance Company (incorporated by reference  to Exhibit 10.12 to Amendment No. 2 to Registration Statement on  Form S-1 filed October 12, 2004).                                                                                                                                                                                                                                                                                                           |
| 10.17      |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| 10.18      |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| 10.19      |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

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| 10.20 |   | Form of Restricted  Unit Grant (Directors) (incorporated by reference to Exhibit 10.1 to  Current Report on Form 8-K filed December 15, 2004).                                                                                                                                                                                                      |
|-------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.21 |   | Form of  Grant of Options (incorporated by reference to Exhibit 10.17 to  Quarterly Report on Form 10-Q filed December 21, 2004).                                                                                                                                                                                                                   |
| 10.22 |   | Form of  Restricted Unit Grant (Employees) (incorporated by reference to  Exhibit 4.4 to Registration Statement on Form S-8 filed  February 11, 2005).                                                                                                                                                                                              |
| 10.23 |   | 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).                                                                                                                                                    |
| 10.24 |   | 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). |
| 10.25 |   | 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).                                                                                                                                                                                           |
| 10.26 |   | 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).                                                                                                                                                    |
| 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.                                                                                                                                                                                                                                                |
| 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.                                                                                                                                                                                                                                                |

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*                    Filedherewith.

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

 

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