##### Table of Contents



UNITED STATES SECURITIES AND
    EXCHANGE COMMISSION
 Washington, D.C.
    20549
 Form 10-K
  þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
    OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31, 2006ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)  OF
    THE SECURITIES EXCHANGE ACT OF 1934For the transition period
    from          to   Commission file number:
    001-32329
 Copano Energy, L.L.C.
 (Exact name of registrant as
    specified in its charter)
  Delaware

51-0411678(State of
    organization)

(I.R.S. Employer Identification
    No.)2727 Allen Parkway,
    Suite 1200

77019Houston, Texas

(Zip Code)(Address of principal executive
    offices)(713) 621-9547(Registrants
    telephone number, including area code   None
 (Former name, former address and
    former fiscal year, if changed since last report)
  SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE
    ACT:
  Title of Each Class

Name of Exchange on Which RegisteredCommon Units Representing
    Limited
    Liability Company Interests

The NASDAQ Stock Market LLC   SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE
    ACT:
  Title of Class
  None
  þ o
  o þ
  þ o
  Regulation S-K Form 10-K Form 10-K. þ
  Rule 12b-2
 Large accelerated
    filer  o     Accelerated
    filer  þ     Non-accelerated
    filer  o
  Rule 12b-2 o þ
      DOCUMENTS INCORPORATED BY
    REFERENCE:
  Document

Parts Into Which IncorporatedPortions of the Proxy Statement
    for the Annual Meeting of Unitholders of Copano Energy, L.L.C.
    to be held May 24, 2007

Part III




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##### 



TABLE OF
    CONTENTS
  PagePART IItem 1.


Business


1Item 1A.


Risk
    Factors


26Item 1B.


Unresolved Staff
    Comments


39Item 2.


Properties


39Item 3.


Legal
    Proceedings


40Item 4.


Submission of
    Matters to a Vote of Security Holders


40PART IIItem 5.


Market for
    Registrants Common Equity, Related Unitholder Matters and
    Issuer Purchases of Equity Securities


41Item 6.


Selected Financial
    Data


44Item 7.


Managements
    Discussion and Analysis of Financial Condition and Results of
    Operation


48Item 7A.


Quantitative and
    Qualitative Disclosures about Market Risk


74Item 8.


Financial
    Statements and Supplementary Data


78Item 9.


Changes in and
    Disagreements With Accountants on Accounting and Financial
    Disclosure


78Item 9A.


Controls and
    Procedures


79Item 9B.


Other
    Information


83PART IIIItem 10.


Directors and
    Executive Officers of the Registrant


84Item 11.


Executive
    Compensation


84Item 12.


Security Ownership
    of Certain Beneficial Owners and Management and Related
    Unitholder Matters


84Item 13.


Certain
    Relationships and Related Parties


84Item 14.


Principal
    Accountant Fees and Services


84PART IVItem 15.


Exhibits and
    Financial Statement Schedules


85Consent of Deloitte & Touche LLPSection 302 Certification of CEOSection 302 Certification of CFOSection 906 Certification of CEOSection 906 Certification of CFO   i




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##### Table of Contents



PART I  Unless the context requires otherwise, references to
    Copano, we, our,
    us or like terms refer to Copano Energy, L.L.C. and
    its wholly-owned subsidiaries.
  As generally used in the energy industry and in this Annual
    Report, the following terms have the following meanings:
  $/gal:

U.S. dollars per
    gallonBbls:

BarrelsBbls/d:

Barrels per dayBtu:

British thermal unitsMcf:

One thousand cubic
    feetMcf/d:

One thousand cubic feet per
    dayMMBtu:

One million British thermal
    unitsMMcf:

One million cubic
    feetMMBtu/d:

One million British thermal
    units per dayMMcf/d:

One million cubic feet per
    dayNGLs:

Natural gas liquids which
    consist primarily of ethane, propane, isobutane, normal butane,
    natural gasoline and stabilized condensateresidue gas:

The pipeline quality natural
    gas remaining after natural gas is processedthroughput:

The volume of product
    transported or passing through a pipeline, plant, terminal or
    other facility   Item 1.
    Business  General
  NASDAQ
  104-mile 46-mile
  Recent
    Developments
  Public Equity Offering and Reduction of
    Debt.
  Fourth Quarter 2006 Hedge Activity.
 1




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Amended and Restated Revolving Credit
    Facility.
  Declaration of Distribution.
  Conversion of Subordinated Units. one-for-one
  Unit Split. two-for-one
  Business
    Strategy
    
    Pursuing growth from our existing assets.  Our
    pipelines and processing plants have excess capacity, which
    provides us with opportunities to increase throughput volume
    with minimal incremental costs. We seek to increase cash flow
    from our existing assets by aggressively marketing our services
    to producers to connect new supplies of natural gas and increase
    volumes and utilization.
    Pursuing complementary acquisitions and organic expansion
    opportunities.  We seek to use our acquisition and
    integration experience to continue to make complementary
    acquisitions of midstream 2




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assets in our operating areas that provide opportunities to
    expand either the acquired assets or our existing assets to
    increase utilization. We pursue acquisitions that we believe
    will allow us to capitalize on our existing infrastructure,
    personnel, and producer and customer relationships to strengthen
    our existing integrated package of services. Also, we seek to
    expand our assets where appropriate to meet increased demand for
    our midstream services.  
    Reducing the sensitivity of our cash flows to commodity price
    fluctuations.  Because of the volatility of
    natural gas and NGL prices, we attempt to structure our
    contracts in a manner that allows us to achieve positive gross
    margins in a variety of market conditions. In our contracts for
    services provided by our Texas Gulf Coast Processing segment, we
    focus on arrangements pursuant to which we are paid a fee to
    condition natural gas when processing is economically
    unattractive. In our contracts with producers within our
    Mid-Continent Operations and Texas Gulf Coast Pipelines
    segments, we focus on arrangements pursuant to which the fee
    received for the services we deliver is sufficient to provide us
    with positive operating margins irrespective of commodity prices.    
    Exploiting the operating flexibility of our
    assets.  We can modify the operation of our assets
    to maximize our cash flows. For example, our ability to
    condition natural gas at our Houston Central Processing Plant,
    rather than to fully process it, provides us with significant
    benefits during periods when fully processing natural gas is not
    profitable. We continually monitor natural gas and NGL prices to
    quickly switch between processing and conditioning modes when it
    is economically appropriate to do so. In addition, we will
    continue to utilize our ability to reject ethane at our Houston
    Central Processing Plant, Paden Processing Plant and Glenpool
    Processing Plant, as market conditions warrant. We also consider
    alternative natural gas sales options at the tailgate of our
    Houston Central Processing Plant and alternative sources of
    natural gas supply on our Upper Gulf Coast pipeline system.
    Expanding our geographic scope into new regions where our
    growth strategy can be applied.  We pursue
    opportunities to acquire assets in new regions where we believe
    growth opportunities are attractive and our business strategies
    could be applied.  Risk
    Factors
  page F-1.
  Our
    Operations
   3




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Mid-Continent Operations Segment.
  
    3,376 miles of pipelines in eight primarily low-pressure
    gathering systems extending through counties encompassing an
    aggregate area of approximately 16,900 square miles, with
    combined throughput capacity of 231 MMcf/d; and
    four processing plants, including the Southern Dome Processing
    Plant, with a combined inlet capacity of approximately
    115 MMcf/d.    Texas Gulf Coast Pipelines Segment.
  Texas Gulf Coast Processing Segment. 104-mile 46-mile Laredo-to-Katy
   4




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Mid-Continent
    Operations Segment
      
 5




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Year EndedDecember 31, 2006Existing


AverageThroughput


Throughput


UtilizationLength


Capacity


Volumes


of(miles)


(Mcf/d)(2)


(Mcf/d)


CapacityGathering PipelinesStroud System


742



107,000



78,683



73.5
%Osage System


549



24,000



17,783



74.1
%Milfay System


372



15,000



12,465



83.1
%Glenpool System


1,015



24,000



9,380



39.1
%Twin Rivers System


534



16,000



11,334



70.8
%Mountain Systems(1)


164



45,000



17,521



38.9
%Total


3,376



231,000



147,166



63.7
%   Year EndedDecember 31, 2006Existing


AverageThroughput


Inlet


UtilizationCapacity


Volumes


of(Mcf/d)(2)


(Mcf/d)


CapacityProcessing PlantsPaden


60,000



46,931



78.2
%Milfay


15,000



11,467



76.4
%Glenpool


25,000



8,734



34.9
%Southern Dome(3)


15,000



2,312



15.4
%Total


115,000



69,444



60.4
%     (1)
    
    The Mountain Systems consists of three systems: Blue Mountain,
    Cyclone Mountain and Pine Mountain.(2)
    
    Many capacity values are based on current operating
    configurations and could be increased through additional
    compression, increased delivery meter capacity
    and/or other
    facility upgrades including, for example, larger dehydration
    capacity.(3)
    
    We hold a majority interest in Southern Dome, which owns the
    Southern Dome Processing Plant. The plants design capacity
    is 30,000 Mcf/d but is currently configured for an
    operating capacity of 15,000 Mcf/d.  Stroud
    System
   6




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Osage
    System
     7




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##### Table of Contents



Milfay
    System
      Glenpool
    System
    8,536 MMBtu/d
  Twin
    Rivers System
     8




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Mountain
    Systems
      Southern
    Dome
  3.4-mile
      Mid-Continent
    Operations Natural Gas Supply
       9




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Competition
    in Our Mid-Continent Operating Region
         10




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Our Texas
    Gulf Coast Operations
    
 11




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Texas
    Gulf Coast Pipelines Segment
    Year EndedDecember 31, 2006Existing


AverageThroughput


Throughput


UtilizationLength


Capacity


Volumes


ofPipeline Type

(Miles)


(Mcf/d)(1)


(Mcf/d)


CapacitySouth Texas RegionAgua Dulce System(2)

Gathering and Transmission


445



102,000



22,066



22%Hebbronville System

Gathering


79



62,700



39,283



63%Karnes System

Gathering


103



17,500



6,182



35%Live Oak System

Gathering


143



96,600



21,852



23%Webb/Duval System(3)(4)

Gathering


144



219,000



102,691



47%Coastal Waters Region

Gathering


143



41,000



3,132



8%Central Gulf Coast
    Region

Gathering


311



239,000



119,115



50%Upper Gulf Coast
    Region

Gathering and Transmission


230



139,000



31,364



23%Total




1,598







345,685     (1)
    
    Many capacity values are based on current operating
    configurations and could be increased through additional
    compression, increased delivery meter capacity
    and/or other
    facility upgrades including, for example, larger dehydration
    capacity.(2)
    
    Throughput volumes presented in the table are net of
    intercompany transactions. Gross volumes and utilization of
    capacity in this area totaled 22,463 Mcf/d and 23%,
    respectively, for the year ended December 31, 2006.(3)
    
    Our Webb/Duval System is owned by Webb Duval, an unconsolidated
    partnership in which we hold a 62.5% interest.(4)
    
    Throughput volumes presented in the table are net of affiliate
    transactions. Gross volumes and utilization of capacity in this
    area totaled 113,016 Mcf/d and 52%, respectively, for the
    year ended December 31, 2006.  South
    Texas Region
    Agua
    Dulce System
  Laredo-to-Katy and/or
 12




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Hebbronville
    System
  Laredo-to-Katy
    Karnes
    System
  Laredo-to-Katy
    Live Oak
    System
  Laredo-to-Katy and/or
    Webb/Duval
    System
    144-mile 3-inch 16-inch 6-mile, 12-inch Laredo-to-Katy
   13




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Coastal
    Waters Region
        23-mile
  Central
    Gulf Coast Region
            Upper
    Gulf Coast Region
   14




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77-mile
  28-mile 6-inch 8-inch
  Texas
    Gulf Coast Processing Segment
      Year Ended December 31, 2006Existing

NGLs


Average Inlet


AverageTexas Gulf Coast

Length


Throughput

Produced


Volumes


Throughput


CapacityProcessing Segment

(Miles)


Capacity

(Bbls/d)


(Mcf/d)


Volumes (Bbls/d)


UtilizationHouston Central Processing Plant





700,000 (Mcf/d)


14,740



495,600







71
%Sheridan NGL Pipeline-West
    Segment(1)


66


18,900 (Bbls/d)










12,405



66
%Brenham NGL Pipeline(2)


46













N/A



N/ASheridan NGL Pipeline-East
    Segment(3)(4)


21


12,000 (Bbls/d)










85
(4)


1
%(4)Sheridan NGL Pipeline-Central
    Segment(5)


17


18,900 (Bbls/d)














N/A     (1)
    
    Excludes throughput capacity for transportation of butylene
    volumes on East Segment. See footnote (3) below.(2)
    
    We expect to place the Brenham NGL Pipeline into service in 2007.(3)
    
    In October 2006 and pursuant to a contract with Texas
    Petrochemical Company, we began transporting small volumes of
    butylene on a western portion of our Sheridan NGL Pipeline that
    was not being used for transportation of NGLs from our Houston
    Central Processing Plant. 15




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(4)
    
    The average throughput for the Sheridan NGL Pipeline-East
    Segment was 1,004 Bbls/d for October 2006, the only month
    of flow on this pipeline during 2006 under the Texas
    Petrochemical Company contract.(5)
    
    Currently inactive.  Houston
    Central Processing Plant
  Laredo-to-Katy
  gallon-per-minute gallons-per-minute 8-inch 6-inch 163-acre
    
    providing us with the ability to minimize the level of NGLs
    removed from the natural gas stream during periods when natural
    gas prices are high relative to NGL prices; and
    allowing us to operate our Houston Central Processing Plant more
    efficiently at a much reduced fuel consumption rate while still
    meeting downstream pipeline hydrocarbon dew point specifications.     16




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Sheridan
    NGL Pipeline
  104-mile, 6-inch
  Brenham
    NGL Pipeline
  46-mile, 6-inch 5-year
  Our
    Commercial Relationship With Kinder Morgan Texas
    Pipeline
  2,500-mile 30-inch Laredo-to-Katy
   17




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Laredo-to-Katy Laredo-to-Katy
  Competition
    in Our Texas Gulf Coast Operating Region
      Texas
    Gulf Coast Natural Gas Supply
      fee-for-service
 18




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Industry
    Overview
      
  
    Natural gas gathering.  The natural gas
    gathering process begins with the drilling of wells into gas
    bearing rock formations. Once a well has been completed, the
    well is connected to a gathering system. Gathering systems
    generally consist of a network of small diameter pipelines that
    collect natural gas from points near producing wells and
    transport it to larger pipelines for further transmission.
    Gathering systems are operated at design pressures that will
    maximize the total throughput from all connected wells.
    Compression.  Lower pressure gathering systems
    allow wells, which produce at progressively lower field
    pressures as they age, to remain connected to the gathering
    system and continue to produce for longer periods of time. As
    the well pressure declines, it becomes increasingly difficult to
    deliver the remaining production in the ground 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 an existing pressure is compressed to a desired higher
    pressure. Compression allows gas that no longer naturally flows
    into a higher-pressure downstream pipeline to be brought to
    market. Field compression is typically used to allow a gathering
    system to operate at a lower pressure or provide sufficient
    discharge pressure to deliver gas into a higher-pressure
    downstream pipeline. If field compression is not installed, then
    the remaining natural gas in the 19




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ground will not be produced because it cannot overcome the
    higher gathering system pressure. In contrast, if field
    compression is installed, then a well can continue delivering
    natural gas that otherwise would not be produced.  
    Natural gas dehydration.  Some produced natural
    gas is saturated with water, which must be removed because the
    combination of natural gas and water can form ice that can plug
    many different parts of the pipeline gathering and
    transportation system and processing plants. Water in a natural
    gas stream can also cause corrosion when combined with carbon
    dioxide or hydrogen sulfide in natural gas and condensed water
    in the pipeline can raise inlet pipeline pressure and cause a
    greater pressure drop downstream. To avoid these potential
    issues and to meet downstream pipeline and end-user gas quality
    standards, natural gas is often dehydrated to remove the
    saturated water.
    Natural gas treating and blending.  Natural gas
    has a varied composition depending on the field, the formation
    and the reservoir from which it is produced. Natural gas from
    certain formations can be high in carbon dioxide or hydrogen
    sulfide. Natural gas with high carbon dioxide or hydrogen
    sulfide levels may cause significant damage to pipelines and is
    generally not acceptable to end-users. To alleviate the
    potential adverse effects of these contaminants, many pipelines
    regularly inject corrosion inhibitors into the gas stream.
    Additionally, to render natural gas with high carbon dioxide or
    hydrogen sulfide levels marketable, pipelines may blend the gas
    with gas that contains low carbon dioxide or hydrogen sulfide
    levels, or arrange for treatment to remove carbon dioxide and
    hydrogen sulfide to levels that meet pipeline quality standards.
    Amine treating.  The amine treating process
    involves a continuous circulation of a liquid chemical called
    amine that physically contacts with the natural gas. Amine has a
    chemical affinity for hydrogen sulfide and carbon dioxide that
    allows it to absorb the impurities from the gas. After mixing,
    gas and amine are separated and the impurities are removed from
    the amine by heating. The treating plants are sized by the amine
    circulation capacity in terms of gallons per minute.
    Natural gas processing.  The principal
    components of natural gas are methane and ethane, but most
    natural gas also contains varying amounts of other NGLs. Most
    natural gas produced by a well is not suitable for long-haul
    pipeline transportation or commercial use and must be processed
    to remove the heavier hydrocarbon components. Natural gas is
    processed not only to remove unwanted NGLs that would interfere
    with pipeline transportation or use of the natural gas, but also
    to separate from the gas those hydrocarbon liquids that have
    higher value as NGLs. The removal and separation of individual
    hydrocarbons by processing is possible because of differences in
    weight, boiling point, vapor pressure and other physical
    characteristics. Natural gas processing involves the separation
    of natural gas into pipeline quality natural gas and a mixed NGL
    stream.
    Natural gas conditioning.  Conditioning of
    natural gas is the process by which NGLs are removed from the
    natural gas stream by lowering the hydrocarbon dew point
    sufficiently to meet downstream gas pipeline quality
    specifications. Although similar to natural gas processing,
    conditioning of natural gas removes only an absolute minimum
    amount of NGLs (typically the components of pentane and heavier
    products) from the gas stream. To lower the hydrocarbon dew
    point of a natural gas stream, the temperature of the gas is
    reduced. Cryogenic processing consumes more fuel because it
    involves significantly lower temperatures than are required for
    conditioning of natural gas. Conditioning of natural gas, rather
    than processing, is preferred during periods of unfavorable
    processing margins.
    NGL fractionation.  Fractionation is the
    process by which NGLs are further separated into individual,
    more valuable components. NGL fractionation facilities separate
    mixed NGL streams into discrete NGL products: ethane, propane,
    isobutane, normal butane, natural gasoline and stabilized
    condensate. Ethane is primarily used in the petrochemical
    industry as feedstock for ethylene, one of the basic building
    blocks for a wide range of plastics and other chemical products.
    Propane is used both as a petrochemical feedstock in the
    production of ethylene and propylene and as a heating fuel, an
    engine fuel and an industrial fuel. Isobutane is used
    principally to enhance the octane content of motor gasoline.
    Normal butane is used as a petrochemical feedstock in the
    production of ethylene and butylene (a key ingredient in
    synthetic rubber), as a blend stock for motor gasoline and to
    derive isobutane through isomerization. Natural gasoline, a
    mixture of pentanes and heavier hydrocarbons, is used primarily
    as motor gasoline blend stock or petrochemical feedstock. 20




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Stabilized condensate is primarily used as a refinery feedstock
    for the production of motor gasoline and other products.  NGLs are fractionated by heating mixed NGL streams and passing
    them through a series of distillation towers. Fractionation
    takes advantage of the differing boiling points of the various
    NGL products. As the temperature of the NGL stream is increased,
    the lightest (lowest boiling point) NGL product boils off the
    top of the tower where it is condensed and routed to a pipeline
    or storage. The mixture from the bottom of the first tower is
    then moved into the next tower where the process is repeated and
    a different NGL product is separated and stored. This process is
    repeated until the NGLs have been separated into their
    components. Because the fractionation process uses large
    quantities of heat, fuel costs are a major component of the
    total cost of fractionation.  
    Natural gas transportation.  Natural gas
    transportation pipelines receive natural gas from other mainline
    transportation pipelines and gathering systems and deliver the
    natural gas to industrial end-users and utilities and to other
    pipelines.
    NGL transportation.  NGLs are transported to
    market by means of pipelines, pressurized barges, rail car and
    tank trucks. The method of transportation utilized depends on,
    among other things, the existing resources of the transporter,
    the locations of the production points and the delivery points,
    cost-efficiency and the quantity of NGLs being transported.
    Pipelines are generally the most cost-efficient mode of
    transportation when large, consistent volumes of NGLs are to be
    delivered.  Risk
    Management
    Regulation
  Regulation by the FERC of Interstate Natural Gas
    Pipelines.
  
    the certification and construction of new facilities;
    the extension or abandonment of services and facilities;
    the maintenance of accounts and records;
    the acquisition and disposition of facilities;
    the initiation and discontinuation of services; and
    various other matters.   21




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##### Table of Contents



Intrastate Pipeline Regulation.
    Gathering Pipeline
    Regulation.
      Sales of Natural Gas.
 22




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##### Table of Contents



Environmental
    Matters
    
    restricting the way we can handle or dispose of wastes;
    limiting or prohibiting construction and operating activities in
    sensitive areas such as wetlands, coastal regions, or areas
    inhabited by endangered species;
    requiring remedial action to mitigate pollution conditions
    caused by our operations or attributable to former
    operators; and
    enjoining the operations of facilities deemed in non-compliance
    with permits issued pursuant to such environmental laws and
    regulations.        Hazardous Waste.
 23




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##### Table of Contents



Site Remediation.
    Air Emissions.
  Water Discharges.
  Pipeline Safety.
 24




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##### Table of Contents



Employee Health and Safety.
  Other Laws and Regulations. and/or Massachusetts, et
    al v. EPA
  Office
    Facilities
   25




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##### Table of Contents



Employees
    Available
    Information
  1-800-SEC-0330.
  (713-621-9547) Form 10-K, Form 10-Q, Form 8-K
  Item 1A.
    Risk
    Factors  In addition to the factors discussed elsewhere in this Annual
    Report, including the financial statements and related notes,
    you should consider carefully the risks and uncertainties
    described below, which could materially adversely affect our
    business, financial condition and results of operations. While
    these are the risks and uncertainties we believe are most
    important, you should know that they are not the only risks or
    uncertainties facing us or which may adversely affect our
    business. If any of the following risks or uncertainties were to
    occur, our business, financial condition or results of operation
    could be adversely affected. Additional risks and uncertainties
    not presently know to us or that we currently deem immaterial
    also may impair our business operations and financial
    condition.
  Risks
    Related to Our Business
  We may
    not have sufficient cash from operations each quarter to pay the
    minimum quarterly distribution following establishment of cash
    reserves and payment of fees and expenses.
   26




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##### Table of Contents




    the amount of natural gas gathered and transported on our
    pipelines;
    the amount and NGL content of the natural gas we process;
    the price of natural gas, NGLs and crude oil;
    the relationship between natural gas and NGL prices;
    the level of our operating costs and the impact of inflation on
    those costs;
    the weather in our operating areas;
    the level of competition from other midstream energy companies;
    and
    the fees we charge and the margins we realize for our services.    
    the level of capital expenditures we make;
    the cost of acquisitions, if any;
    our debt service requirements;
    fluctuations in our working capital needs;
    restrictions on distributions contained in our senior secured
    revolving credit facility and the indenture governing our
    81/8% Senior
    Notes due 2016 (Senior Notes);
    our ability to make eligible working capital borrowings under
    our senior secured revolving credit facility to pay
    distributions;
    prevailing economic conditions; and
    the amount of cash reserves established by our Board of
    Directors for the proper conduct of our business.    To the
    extent that we make acquisitions in the future and our
    acquisitions do not perform as expected, our future financial
    performance may be negatively impacted.
      
    operating a significantly larger combined organization and
    adding operations;
    difficulties in the assimilation of the assets and operations of
    the acquired businesses, especially if the assets acquired are
    in a new business segment or geographic area;
    the risk that natural gas reserves expected to support the
    acquired assets may not be of the anticipated magnitude or may
    not be developed as anticipated;
    the loss of significant producers or markets or key employees
    from the acquired businesses;
    the diversion of managements attention from other business
    concerns; 27




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##### Table of Contents




    the failure to realize expected profitability or growth;
    the failure to realize any expected synergies and cost savings;
    coordinating geographically disparate organizations, systems and
    facilities; and
    coordinating or consolidating corporate and administrative
    functions.    Our
    acquisition of ScissorTail could expose us to potential
    significant liabilities.
    Our
    substantial indebtedness could limit our operating flexibility
    and impair our ability to fulfill our debt
    obligations.
    
    total indebtedness of $255.0 million, including
    indebtedness associated with our Senior Notes and our senior
    secured revolving credit facility; and
    availability under our senior secured revolving credit facility
    of approximately $170.0 million.    
    make it more difficult for us to satisfy our obligations with
    respect to our indebtedness;
    impair our ability to obtain additional financing in the future
    for working capital, capital expenditures, acquisitions, general
    company purposes or other purposes;
    result in higher interest expense in the event of increases in
    interest rates to the extent that any of our debt is subject to
    variable rates of interest;
    have a material adverse effect on us if we fail to comply with
    financial and restrictive covenants in our debt agreements and
    an event of default occurs as a result of that failure that is
    not cured or waived;
    require us to dedicate a substantial portion of our cash flow to
    payments on our indebtedness and other financial obligations,
    thereby reducing the availability of our cash flow to fund
    working capital, capital expenditures and other general company
    requirements;
    limit our flexibility in planning for, or reacting to, changes
    in our business and the industry in which we operate; and
    place us at a competitive disadvantage compared to any
    competitors that have proportionately less debt. 28




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##### Table of Contents



Restrictive
    covenants in the agreements governing our indebtedness may
    reduce our operating flexibility.
    
    sell assets;
    pay distributions on, redeem or repurchase our equity interests
    or redeem or repurchase our subordinated debt, if any;
    make investments;
    incur or guarantee additional indebtedness or issue preferred
    units;
    create or incur certain liens;
    enter into agreements that restrict distributions or other
    payments from our restricted subsidiaries to us;
    consolidate, merge or transfer all or substantially all of our
    assets;
    engage in transactions with affiliates;
    create unrestricted subsidiaries; and
    enter into sale and leaseback transactions.    Our
    future success depends on our ability to continually obtain new
    sources of natural gas supply, and any decrease in supplies of
    natural gas could adversely affect our revenues and operating
    income.
     29




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##### Table of Contents



If
    KMTPs
    Laredo-to-Katy
    pipeline becomes unavailable to transport natural gas to or from
    our Houston Central Processing Plant for any reason, then our
    cash flow and revenue could be adversely affected.
  Laredo-to-Katy Laredo-to-Katy Laredo-to-Katy Laredo-to-Katy
    We
    generally do not obtain independent evaluations of natural gas
    reserves dedicated to our pipeline systems; therefore, volumes
    of natural gas transported on our pipeline systems in the future
    could be less than we anticipate, which may cause our revenues
    and operating income to be less than we expect.
   30




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##### Table of Contents



We are
    exposed to the credit risk of our customers and counterparties,
    and a general increase in the nonpayment and nonperformance by
    our customers could have an adverse impact on our financial
    condition and results of operations.
    Our
    profitability depends upon prices and market demand for natural
    gas and NGLs, which are beyond our control and have been
    volatile.
                
    the impact of weather on the demand for oil and natural gas;
    the level of domestic oil and natural gas production;
    the availability of imported oil, natural gas, liquefied natural
    gas and NGLs; 31




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##### Table of Contents




    actions taken by foreign oil and gas producing nations;
    the availability of local, intrastate and interstate
    transportation systems;
    the availability and marketing of competitive fuels;
    the impact of energy conservation efforts; and
    the extent of governmental regulation and taxation.  A
    change in the characterization of some of our assets by federal,
    state or local regulatory agencies or a change in policy by
    those agencies may result in increased regulation of our assets,
    which may cause our revenues to decline and operating expenses
    to increase.
        Compliance
    with pipeline integrity regulations issued by the TRRC and OCC
    could result in substantial expenditures for testing, repairs
    and replacement.
   32




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##### Table of Contents



Because
    we handle natural gas and other petroleum products in our
    pipeline and processing businesses, we may incur significant
    costs and liabilities in the future resulting from a failure to
    comply with new or existing environmental regulations or an
    accidental release of hazardous substances into the
    environment.
      Expanding
    our business by constructing new assets will subject us to risks
    that projects may not be completed on schedule, the costs
    associated with the projects may exceed our expectations and
    additional natural gas supplies may not be available following
    completion of the projects, which could cause our revenues to be
    less than anticipated. Our operating cash flows from our capital
    projects may not be immediate.
   33




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##### Table of Contents



If the
    cost of renewing existing
    rights-of-way
    increases, it may have an adverse impact on our profitability.
    In addition, if we are unable to obtain new
    rights-of-way,
    then we may be unable to fully execute our growth
    strategy.
  rights-of-way rights-of-way rights-of-way rights-of-way. rights-of-way rights-of-way
  Our
    business involves many hazards and operational risks, some of
    which may not be fully covered by insurance. If a significant
    accident or event occurs that is not fully insured, our
    operations could be temporarily or permanently impaired, and our
    liabilities and expenses could be significant.
    
    damage to pipelines, pipeline blockages and damage to related
    equipment and surrounding properties caused by hurricanes,
    tornadoes, floods, fires, extreme weather conditions and other
    natural disasters and acts of terrorism;
    inadvertent damage from motor vehicles, construction or farm
    equipment;
    leaks of natural gas, NGLs and other hydrocarbons;
    operator error; and
    fires and explosions.  and/or
 34




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##### Table of Contents



Due to
    our limited asset diversification, adverse developments in our
    gathering, transportation, processing and related businesses
    would have a significant impact on our results of
    operations.
    If we
    fail to maintain an effective system of internal control over
    financial reporting, we may not be able to accurately report our
    financial results or prevent fraud. As a result, we may
    experience materially higher compliance costs.
    Risks
    Related to Our Structure
  Our
    limited liability company agreement prohibits a unitholder who
    acquires 15% or more of our common units without the approval of
    our Board of Directors from engaging in a business combination
    with us for three years. This provision could discourage a
    change of control that our unitholders may favor, which could
    negatively affect the price of our common units.
   35




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##### Table of Contents



Our
    cap on certain general and administrative expenses expires on
    December 31, 2007. Once the cap expires, our pre-IPO
    investors will no longer be required to reimburse us for certain
    amounts in excess of the cap, which could materially reduce the
    cash available for distribution to our
    unitholders.
    Year

General and Administrative Expense Limitation1

$
1.50 million per quarter2

$
1.65 million per quarter3

$
1.80 million per quarter       Distributions
    to our pre-IPO investors may be insufficient to allow them to
    reimburse us for all of our general and administrative expenses
    in excess of the cap, which could materially reduce the cash
    available for distributions to our unitholders.
    We may
    issue additional common units without your approval, which would
    dilute your existing ownership interests.
      
    your proportionate ownership interest in us will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    the relative voting strength of each previously outstanding unit
    will be diminished; and
    the market price of the common units may decline. 36




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##### Table of Contents



Our
    limited liability company agreement provides for a limited call
    right that may require you to sell your common units at an
    undesirable time or price.
    Certain
    of our investors may sell units in the public market, which
    could reduce the market price of our outstanding common
    units.
  one-for-one Form S-3, Form S-3, Form S-3
  Tax Risks
    to Common Unitholders
  Our
    tax treatment depends on our status as a partnership for federal
    income tax purposes, as well as our not being subject to a
    material amount of entity-level taxation by individual states.
    If the IRS were to treat us as a corporation for tax purposes or
    we were to become subject to a material amount of
    entity-level
    taxation, it would substantially reduce the amount of cash
    available for distribution to our unitholders.
       37




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##### Table of Contents



If the
    IRS contests the federal income tax positions we take, the
    market for our common units may be adversely impacted, and the
    costs of any IRS contest will reduce cash available for
    distribution to our unitholders.
    A
    unitholder will be required to pay taxes on the share of our
    income allocated to you even if you do not receive any cash
    distributions from us.
    Tax
    gain or loss on disposition of our common units could be more or
    less than expected.
    Tax-exempt
    entities and foreign persons face unique tax issues from owning
    common units that may result in adverse tax consequences to
    them.
  non-U.S. persons non-U.S. persons non-U.S. persons non-U.S. person,
 38




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##### Table of Contents



We
    treat each purchaser of our common units as having the same tax
    benefits without regard to the actual common units purchased.
    The IRS may challenge this treatment, which could adversely
    affect the value of the common units.
    The
    sale or exchange of 50% or more of our capital and profits
    interests during any twelve-month period will result in the
    technical termination of our partnership for federal income tax
    purposes.
    As a
    result of investing in our common units, you may be subject to
    state and local taxes and return filing requirements in states
    where you do not live.
    Item 1B.
    Unresolved
    Staff Comments    Item 2.
    Properties  rights-of-way rights-of-way right-of-way
  rights-of-way,
 39




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##### Table of Contents



Item 3.
    Legal
    Proceedings  time-to-time,
  Item 4.
    Submission
    of Matters to a Vote of Security Holders   40




---



##### Table of Contents



PART II  Item 5.
    Market
    for Registrants Common Equity, Related Unitholder Matters
    and Issuer Purchases of Equity Securities  NASDAQ one-for-one
    Common Unit


CashPrice Range


DistributionHigh


Low


Paid per Unit2006:Quarter Ended December 31

$
63.34


$
52.75


$
0.800Quarter Ended September 30

$
54.80


$
46.73


$
0.750Quarter Ended June 30

$
49.76


$
43.27


$
0.675Quarter Ended March 31

$
44.95


$
38.10


$
0.6002005:Quarter Ended December 31

$
39.90


$
34.10


$
0.550Quarter Ended September 30

$
44.60


$
36.00


$
0.500Quarter Ended June 30

$
36.90


$
27.76


$
0.450
(1)Quarter Ended March 31

$
31.48


$
25.47


$
0.420     (1)
    
    There was also a concurrent quarterly distribution of
    $0.495 per unit with respect to 4,830,758 Class B
    units issued in connection with the closing of our acquisition
    of ScissorTail on August 1, 2005. The Class B unit
    distribution represented a quarterly distribution equal to 110%
    of the per unit distribution received by the common units as
    required by the terms of the Class B units. On
    October 27, 2005, our unitholders approved the conversion
    of each of the Class B units into one common unit and the
    issuance of 4,830,758 additional common units upon such
    conversion.  two-for-one two-for-one
     41




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##### Table of Contents



One Quarter


Four QuartersCommon units(1)

$
17,025


$
68,099     (1)
    
    Includes restricted common units issued under our Long-Term
    Incentive Plan, or LTIP. Distributions made on restricted units
    issued to date are subject to the same vesting provisions as the
    restricted units. As of February 1, 2007, we had 158,208
    outstanding restricted units. Annual distributions related to
    these restricted units are approximately $0.5 million.  one-for-one one-for-one
  Unitholder
    Return Performance Presentation
   42




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##### Table of Contents



November 9,

Year Ended December 31,2004

2004

2005

2006Copano Energy, L.L.C.(CPNO)

$
100


$
126
(1)

$
180
(2)

$
288
(3)Alerian Total Return Index (AMZX)

$
100


$
105


$
112


$
141S&P 500 Index (SPX)

$
100


$
104


$
107


$
122     (1)
    
    Based on the last reported sale price of our common units as
    reported on the NASDAQ on December 31, 2004 ($28.50).(2)
    
    Based on the last reported sale price of our common units as
    reported on the NASDAQ on December 30, 2005 ($39.05).(3)
    
    Based on the last reported sale price of our common units as
    reported on the NASDAQ on December 29, 2006 ($59.60).    Securities
    Authorized for Issuance Under Equity Compensation
    Plans
    Issuer
    Purchases of Equity Securities
    Recent
    Sales of Unregistered Securities
   43




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##### Table of Contents



Item 6.
    Selected
    Financial Data  Selected
    Historical Consolidated Financial and Operating Data
     44




---



##### Table of Contents



Year Ended December 31,2006


2005(1)


2004


2003


2002(In thousands, except per unit data)Summary of Operations
    Data:Revenues

$
860,272


$
747,743


$
437,656


$
384,571


$
224,896Cost of sales


672,184



643,652



386,155



353,376



199,525Operations and maintenance expenses


32,484



18,459



12,486



10,854



9,562Depreciation and amortization


31,993



17,052



7,287



6,091



5,539General and administrative expenses


26,535



18,156



9,217



5,849



4,177Taxes other than income


2,061



1,178



770



926



891Equity in (earnings) loss from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)


127



584Operating income


96,312



50,173



22,160



7,348



4,618Interest income and other


1,706



640



85



43



101Interest and other financing costs


(32,904
)


(20,461
)


(23,160
)


(12,108
)


(6,360
)Net income (loss)

$
65,114


$
30,352


$
(915
)

$
(4,717
)

$
(1,641
)Basic net income (loss) per common
    unit:(2)

$
3.54


$
2.31


$
(0.35
)

$
(6.21
)

$
(6.77
)Diluted net income (loss) per
    common unit:(2)

$
3.49


$
2.29


$
(0.35
)

$
(6.21
)

$
(6.77
)Cash distributions per common
    unit:(2)

$
2.58


$
1.57


$
1.01


$



$
0.22Balance Sheet Data (at period
    end):Total assets

$
839,058


$
792,750


$
178,399


$
161,709


$
159,521Property, plant and equipment, net


566,927



532,320



119,683



117,032



116,888Payables to affiliates


123



189



127



1,371



932Long-term debt


255,000



398,000



57,000



57,898



68,740Redeemable preferred units














60,982



53,559Members capital


472,586



281,803



82,356



(662
)


6,577Cash Flow Data:Net cash flow provided by (used in):Operating activities

$
91,679


$
280


$
17,697


$
15,296


$
8,865Investing activities


(70,291
)


(491,708
)


(8,920
)


(6,192
)


(16,817
)Financing activities


(7,201
)


509,710



(6,369
)


(9,633
)


(2,591
)Other Financial Data:Segment Gross Margin:Mid-Continent Operations(3)

$
95,614


$
40,683


$



$



$
Texas Gulf Coast Pipelines


40,544



32,857



30,076



27,551



18,772Texas Gulf Coast Processing


50,577



30,191



21,425



3,644



6,599Corporate


1,353



360











Total segment gross margin

$
188,088


$
104,091


$
51,501


$
31,195


$
25,371EBITDA(4)

$
130,011


$
67,865


$
29,532


$
13,482


$
10,258Maintenance capital expenditures(5)

$
8,984


$
5,394


$
1,790


$
2,281


$
3,781Expansion capital expenditures(6)


53,298



487,578



7,130



3,911



9,323Total capital expenditures

$
62,282


$
492,972


$
8,920


$
6,192


$
13,104 45




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##### Table of Contents



Year Ended December 31,2006


2005(1)


2004


2003


2002(In thousands, except per unit data)Operating Data:Mid-Continent Operations:(3)Pipeline throughput (Mcf/d)


147,166



132,011











Plant inlet volumes (Mcf/d)


102,556



87,977











NGLs produced (Bbls/d)


11,811



9,146











Texas Gulf Coast Pipelines:Pipeline throughput(7) (Mcf/d)


242,994



214,774



220,970



238,800



247,613Texas Gulf Coast Processing:Plant inlet volumes (Mcf/d)


495,600



530,346



529,040



479,127



571,217NGLs produced (Bbls/d)


14,740



13,066



15,373



7,280



12,656     (1)
    
    Our summary financial and operating data as of and for the year
    ended December 31, 2005 include the results of our
    Mid-Continent Operations from August 1, 2005 (the date we
    acquired ScissorTail) through December 31, 2005.(2)
    
    Net income (loss) per unit is based on the weighted average of
    total equivalent units outstanding during the periods presented.
    For periods prior to our IPO, equivalent units were calculated
    using the weighted average of pre-IPO common units and common
    special units adjusted by a conversion or exchange factor. The
    computation of diluted units outstanding for all periods
    presented excludes incremental units related to warrants
    previously held by preferred unitholders and employee unit
    options because these equity securities had an anti-dilutive
    effect as a result of losses reported by us for these periods.
    Cash distributions for 2002 have been restated to reflect the
    conversion discussed previously and the cash distributions for
    2004 relate to the distributions paid to the pre-IPO unitholders
    prior to our IPO and are based on equivalent units.(3)
    
    Plant inlet throughput and NGLs produced represent total volumes
    processed and produced by the Mid-Continent Operations segment
    at all plants, including our own plants and plants owned by
    third parties. For the year ended December 31, 2006, plant
    inlet throughput averaged 67,131 Mcf/d and NGLs produced
    averaged 7,989 Bbls/d for plants owned by the Mid-Continent
    Operations segment. For the period from August 1, 2005
    through December 31, 2005, plant inlet throughput averaged
    54,893 Mcf/d and NGLs produced averaged 5,500 Bbls/d
    for plants owned by the Mid-Continent Operations segment. This
    data excludes results and volumes associated with our interest
    in Southern Dome.(4)
    
    Under the equity method of accounting, these amounts include our
    equity in the earnings of Webb Duval and Southern Dome, in the
    amounts of $1,297, $927 and $419 for the years ended
    December 31, 2006, 2005 and 2004, respectively.(5)
    
    Maintenance capital expenditures are capital expenditures
    employed to replace partially or fully depreciated assets to
    maintain the existing operating capacity of our assets and to
    extend their useful lives, or other capital expenditures that
    are incurred in maintaining existing system volumes and related
    cash flows.(6)
    
    Expansion capital expenditures represent capital expenditures
    made to expand or increase the efficiency of the existing
    operating capacity of our assets. Expansion capital expenditures
    include expenditures that facilitate an increase in volumes
    within our operations, whether through construction or
    acquisition. For example, expansion of compression facilities to
    increase throughput capacity or the acquisition of additional
    pipelines is considered expansion capital expenditures.
    Expenditures that reduce our operating costs will be considered
    expansion capital expenditures only if the reduction in
    operating expenses exceeds cost reductions typically resulting
    from routine maintenance. Costs for repairs and minor renewals
    to maintain facilities in operating condition, and which do not
    extend the useful life of existing assets, are considered
    operations and maintenance expenses (and not expansion capital
    expenditures) and are expensed as incurred.(7)
    
    Excludes volumes associated with our interest in Webb Duval.
    Volumes transported by Webb Duval, net of intercompany volumes,
    were 102,691 Mcf/d, 106,826 Mcf/d, 104,438 Mcf/d,
    95,341 Mcf/d and 78,737 Mcf/d for the years ended
    December 31, 2006, 2005, 2004, 2003 and 2002, respectively. 46




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##### Table of Contents



Year Ended December 31,2006


2005


2004


2003


2002(In thousands)Reconciliation of total segment
    gross margin to operating income:Operating income

$
96,312


$
50,173


$
22,160


$
7,348


$
4,618Add:Operations and maintenance expenses


32,484



18,459



12,486



10,854



9,562Depreciation and amortization


31,993



17,052



7,287



6,091



5,539General and administrative expenses


26,535



18,156



9,217



5,849



4,177Taxes other than income


2,061



1,178



770



926



891Equity in (earnings) loss from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)


127



584Total segment gross margin

$
188,088


$
104,091


$
51,501


$
31,195


$
25,371Reconciliation of EBITDA to net
    income (loss):Net income (loss)

$
65,114


$
30,352


$
(915
)

$
(4,717
)

$
(1,641
)Add:Depreciation and amortization


31,993



17,052



7,287



6,091



5,539Interest and other financing costs


32,904



20,461



23,160



12,108



6,360EBITDA

$
130,011


$
67,865


$
29,532


$
13,482


$
10,258Reconciliation of EBITDA to cash
    flows from operating activities:Cash flow provided by operating
    activities

$
91,679


$
280


$
17,697


$
15,296


$
8,865Add:Cash paid for interest and other
    financing costs


28,442



14,738



4,029



3,033



2,543Equity in earnings (loss) from
    unconsolidated affiliates


1,297



927



419



(127
)


(584
)Risk management assets


23,014



42,635











(Increase) decrease in working
    capital and other


(14,421
)


9,285



7,387



(4,720
)


(566
)EBITDA

$
130,011


$
67,865


$
29,532


$
13,482


$
10,258  47




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##### Table of Contents



Item 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operation  You should read the following discussion of our financial
    condition and results of operation in conjunction with the
    historical consolidated financial statements and notes thereto
    included elsewhere in this Annual Report. For more detailed
    information regarding the basis of presentation for the
    following information, you should read the notes to the
    historical Consolidated Financial Statements included in
    Item 8 of this Annual Report. In addition, you should
    review Forward-Looking Statements contained in this
    Item 7 of this Annual Report and Risk Factors
    contained in Item 1A of this Annual Report for information
    regarding forward-looking statements made in this discussion and
    certain risks inherent in our business. Other risks involved in
    our business are discussed under Item 7A Quantitative
    and Qualitative Disclosures about Market Risk.
  Overview
      
    Mid-Continent Operations is a provider of natural gas midstream
    services in central and eastern Oklahoma, including natural gas
    gathering and related compression and dehydration services and
    natural gas processing and was established as a segment upon our
    acquisition of ScissorTail on August 1, 2005. For the years
    ended December 31, 2006 and 2005, this segment generated
    approximately 51% and 39%, respectively, of our total segment
    gross margin.
    Texas Gulf Coast Pipelines owns networks of natural gas
    gathering and intrastate pipelines in the Texas Gulf Coast
    region and is engaged in the gathering and intrastate
    transmission of natural gas in areas we sometimes refer to as
    the South Texas, Coastal Waters, Central Gulf Coast and Upper
    Gulf Coast regions. Within this segment, we also provide certain
    related services including compression, dehydration and
    marketing of natural gas. For the years ended December 31,
    2006 and 2005, this segment generated approximately 22% and 32%,
    respectively, of our total segment gross margin.
    Texas Gulf Coast Processing is engaged in natural gas
    processing, conditioning and treating and NGL fractionation and
    transportation through our Houston Central Processing Plant,
    Sheridan NGL Pipeline and, beginning in 2007, our Brenham NGL
    Pipeline. Our natural gas processing plant is the second largest
    in the Texas Gulf Coast region and the third largest in Texas in
    terms of throughput capacity. Our plant is located approximately
    100 miles southwest of Houston, Texas. For the years ended
    December 31, 2006 and 2005, this segment generated
    approximately 27% and 29%, respectively, of our total segment
    gross margin.
    Corporate engages in risk management and other corporate
    activities. For the years ended December 31, 2006 and 2005,
    this segment generated less than 1% of our total segment gross
    margin.     48




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##### Table of Contents



How We
    Evaluate Our Operations
    Throughput Volumes.
  Segment Gross Margin.
   49




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##### Table of Contents



Operations and Maintenance
    Expenses.
  General and Administrative Expenses.
    Year

General and Administrative Expense Limitations1

$
1.50 million per quarter2

$
1.65 million per quarter3

$
1.80 million per quarter     one-for-one
 50




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##### Table of Contents



EBITDA.
  
    the financial performance of our assets without regard to
    financing methods, capital structure or historical cost basis;
    the ability of our assets to generate cash sufficient to pay
    interest costs and support our indebtedness;
    our operating performance and return on capital as compared to
    those of other companies in the midstream energy sector, without
    regard to financing or capital structure; and
    the viability of acquisitions and capital expenditure projects
    and the overall rates of return on alternative investment
    opportunities.    Distributable Cash Flow:
  How We
    Manage Our Operations
    Our Economic Models. percentage-of-index percentage-of-proceeds
 51




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##### Table of Contents



Flow and Transaction Monitoring Systems.
  Producer Activity Evaluation and Reporting.
  Imbalance Monitoring and Control. month-to-month
  Our
    Contracts
    Mid-Continent
    Operations Contracts
  Natural Gas Supply and Transportation. percentage-of-proceeds, percentage-of-index percentage-of-proceeds percentage-of-index
  Percentage-of-Proceeds
    Arrangements. percentage-of-proceeds
 52




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##### Table of Contents



Percentage-of-Index
    Arrangements. percentage-of-index percentage-of-index percentage-of-index percentage-of-proceeds percentage-of-index percentage-of-index percentage-of-proceeds percentage-of-proceeds percentage-of-index
  Fixed-Fee Arrangements.
  Natural Gas Sales and NGL Sales.
  Texas
    Gulf Coast Pipelines Contracts
  fee-for-service fee-for-service fee-for-service
  Natural Gas Purchases. discount-to-index discount-to-index
    Fee-For-Service
    Transport.
 53




---



##### Table of Contents



percentage-of-index percentage-of-index percentage-of-index
  Natural Gas Sales.
  Processing and Conditioning Services.
  Texas
    Gulf Coast Processing Contracts
    
    Keep-Whole with Conditioning Fee
    Arrangements.  Under keep-whole with conditioning
    fee arrangements, we receive natural gas from producers and
    third-party transporters, process or condition the natural gas
    and sell the resulting NGLs to third parties at market prices.
    Under these types of arrangements, we also charge producers and
    third-party transporters a conditioning fee, at all times or in
    certain circumstances depending upon the terms of the particular
    contract. These fees provide us additional revenue and
    compensate us for the services required to redeliver natural gas
    that meets downstream pipeline quality specifications. The
    extraction of NGLs from the natural gas during processing or
    conditioning reduces the Btus of the natural gas, which we are
    required to replace. To keep-whole these producers
    or third-party transporters, we must use a portion of the
    natural gas that we purchase from producers at market prices.
    Accordingly, under these arrangements, our revenues and gross
    margins increase as the price of NGLs increase relative to the
    price of natural gas, and our revenues and gross margins
    decrease as the price of natural gas increases relative to the
    price of NGLs. In the latter case, we are generally able to
    reduce our commodity price exposure by conditioning rather than
    processing the natural gas, as described below. For the year
    ended December 31, 2006, volumes at our Houston Central
    Processing Plant related to this type of fee arrangement
    accounted for 83% of total plant volumes.
    Keep-Whole without Conditioning Fee
    Arrangements.  Under keep-whole without
    conditioning fee arrangements, we receive natural gas from the
    producer or third-party transporter, process the natural gas and
    sell the resulting NGLs to third parties at market prices. Like
    the arrangement described above, under these contracts we are
    required to replace the Btus reduced during processing or
    conditioning. These contracts are subject to all of the
    considerations described in Keep-Whole with Conditioning
    Fee Arrangements above, except that we do not charge the
    producer or transporter a conditioning fee. It is generally not
    our policy to enter into new keep-whole contracts without
    conditioning fee arrangements or pricing provisions that provide
    positive gross margins during conditioning periods. For the year
    ended December 31, 2006, volumes at our Houston Central
    Processing Plant related to this type of fee arrangement
    accounted for 10% of total plant volumes. Our Texas Gulf Coast
    Pipelines segment earned gross margins with respect to these
    volumes pursuant to other provisions of the applicable contracts.
    Percentage-of-Proceeds
    Arrangements.  Under
    percentage-of-proceeds
    arrangements, we generally receive and process natural gas on
    behalf of producers, sell or redeliver the resulting residue gas
    and sell the NGL volumes at index-related prices. We remit to
    producers an agreed upon index-related price for 54




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##### Table of Contents



the natural gas, if not redelivered, and an agreed upon
    percentage of the NGL proceeds. Under these types of
    arrangements, our revenues and gross margins increase as NGL
    prices increase, and our revenues and gross margins decrease as
    NGL prices decrease. For the year ended December 31, 2006,
    volumes at our Houston Central Processing Plant related to this
    type of fee arrangement accounted for 7% of total plant volumes.  
    Fixed-Fee, or Tolling, Arrangements.  Under
    fixed-fee arrangements, producers pay us a fixed fee to process
    their natural gas. These types of arrangements require us to pay
    the producer for all, or substantially all, of the value of NGLs
    recovered and to redeliver the residue gas in exchange for a
    fixed fee. For the year ended December 31, 2006, volumes at
    our Houston Central Processing Plant related to this type of fee
    arrangement accounted for less than 1% of total plant volumes.  agreed-upon
    NGL Product Sales.
  Our Commercial Relationship with Kinder Morgan Texas
    Pipeline. Laredo-to-Katy Laredo-to-Katy Laredo-to-Katy
 55




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##### Table of Contents



Our
    Long-Term Growth Strategy
    Acquisition Analysis.
  Capital Expenditure Analysis.
  Capital Expenditure Analysis.
  Items Impacting
    Comparability of Our Financial Results
  Our
    Acquisitions
   56




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##### Table of Contents



Adoption
    of SFAS No. 123(R)
   57




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##### Table of Contents



Our
    Results of Operation
  Year Ended December 31,2006


2005(1)


2004($ in thousands)Total segment gross margin(2)

$
188,088


$
104,091


$
51,501Operations and maintenance expenses


32,484



18,459



12,486Depreciation and amortization


31,993



17,052



7,287General and administrative expenses


26,535



18,156



9,217Taxes other than income


2,061



1,178



770Equity in earnings from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)Operating income


96,312



50,173



22,160Interest and other financing
    costs, net


(31,198
)


(19,821
)


(23,075
)Net income (loss)

$
65,114


$
30,352


$
(915
)Segment gross margin:Mid-Continent Operations(3)

$
95,614


$
40,683


$
Texas Gulf Coast Pipelines(4)


40,544



32,857



30,076Texas Gulf Coast Processing


50,577



30,191



21,425Corporate


1,353



360



Total segment gross margin(2)

$
188,088


$
104,091


$
51,501Segment gross margin per unit:Mid-Continent Operations:(3)Pipeline throughput ($/MMBtu)

$
1.48


$
1.68



Plant inlet throughput ($/MMBtu)

$
2.09


$
2.49



NGLs produced ($/Bbl)

$
22.18


$
29.07



Texas Gulf Coast Pipelines:Pipeline throughput ($/MMBtu)(4)

$
0.44


$
0.39


$
0.35Texas Gulf Coast Processing:Plant inlet throughput ($/MMBtu)(5)

$
0.27


$
0.15


$
0.10NGLs produced ($/Bbl)(5)

$
9.40


$
6.33


$
3.81 58




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##### Table of Contents



Year Ended December 31,2006


2005(1)


2004($ in thousands)Volumes:Mid-Continent Operations:(3)Pipeline throughput (MMBtu/d)


177,368



158,334



Plant inlet throughput (MMBtu/d)


125,364



106,877



NGLs produced (Bbls/d)


11,811



9,146



Texas Gulf Coast Pipelines:Pipeline throughput (MMBtu/d)(4)


260,442



232,280



239,770Texas Gulf Coast Processing:Plant inlet throughput (MMBtu/d)


522,465



561,085



559,939NGLs produced (Bbls/d)


14,740



13,066



15,373Maintenance capital expenditures(6)

$
8,984


$
5,394


$
1,790Expansion capital expenditures(7)


53,298



487,578



7,130Total capital expenditures

$
62,282


$
492,972


$
8,920Operations and maintenance
    expenses:Mid-Continent Operations

$
17,185


$
5,917


$
Texas Gulf Coast Pipelines


7,232



5,516



5,813Texas Gulf Coast Processing


8,067



7,026



6,673Total operations and maintenance
    expenses

$
32,484


$
18,459


$
12,486    (1)
    
    Our summary financial and operating data for the year ended
    December 31, 2005 include the results of our Mid-Continent
    Operations segment from August 1, 2005 (the date we
    acquired ScissorTail) through December 31, 2005.(2)
    
    Total segment gross margin is a non-GAAP financial measure. For
    a reconciliation of total segment gross margin to its most
    directly comparable GAAP measure, please read Item 6
    Selected Financial Data of this Annual Report.(3)
    
    Segment gross margin per unit amounts for the Mid-Continent
    Operations segment are calculated as the segment gross margin
    divided by the pipeline throughput, inlet throughput or NGLs
    produced, as appropriate. Plant inlet throughput and NGLs
    produced represent total volumes processed and produced by the
    Mid-Continent Operations segment at all plants, including our
    owned plants and plants owned by third parties. For the year
    ended December 31, 2006, plant inlet throughput averaged
    82,045 MMBtu/d and NGLs produced averaged
    7,989 Bbls/day for plants owned by the Mid-Continent
    Operations segment. For the period from August 1, 2005 (the
    date we acquired ScissorTail) through December 31, 2005,
    plant inlet throughput averaged 65,962 MMBtu/d and NGLs
    produced averaged 5,500 Bbls/d for plants owned by the
    Mid-Continent Operations segment. This data excludes results and
    volumes associated with our interest in Southern Dome.(4)
    
    Excludes results and volumes associated with our interest in
    Webb Duval. Volumes transported by Webb Duval, net of
    intercompany volumes, were 117,303 MMBtu/d,
    121,864 MMBtu/d and 118,873 MMBtu/d for the years
    ended December 31 2006, 2005 and 2004, respectively.(5)
    
    Represents the total processing segment gross margin divided by
    the total inlet throughput or NGLs produced, as appropriate.(6)
    
    Maintenance capital expenditures are capital expenditures
    employed to replace partially or fully depreciated assets to
    maintain the existing operating capacity of our assets and to
    extend their useful lives, or other capital expenditures that
    are incurred in maintaining existing system volumes and related
    cash flows.(7)
    
    Expansion capital expenditures represent capital expenditures
    made to expand or increase the efficiency of the existing
    operating capacity of our assets. Expansion capital expenditures
    include expenditures that facilitate an 59




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##### Table of Contents



increase in volumes within our operations, whether through
    construction or acquisition. For example, expansion of
    compression facilities to increase throughput capacity or the
    acquisition of additional pipelines is considered expansion
    capital expenditures. Expenditures that reduce our operating
    costs will be considered expansion capital expenditures only if
    the reduction in operating expenses exceeds cost reductions
    typically resulting from routine maintenance. Costs for repairs
    and minor renewals to maintain facilities in operating
    condition, and which do not extend the useful life of existing
    assets, are considered operations and maintenance expenses (and
    not expansion capital expenditures) and are expensed as incurred.  Year
    Ended December 31, 2006 Compared with Year Ended
    December 31, 2005
  Mid-Continent Operations Segment Gross
    Margin. Mid-Continent
  Texas Gulf Coast Pipelines Segment Gross
    Margin.
  Texas Gulf Coast Processing Segment Gross
    Margin.
  Corporate Segment Gross Margin. mark-to-market
  Operations and Maintenance
    Expenses.
 60




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##### Table of Contents



Depreciation and Amortization.
  General and Administrative Expenses. Mid-Continent
  Interest Expense. one-time
  Year
    Ended December 31, 2005 Compared with Year Ended
    December 31, 2004
  Mid-Continent Operations Segment Gross
    Margin.
  Texas Gulf Coast Pipelines Segment Gross
    Margin.
 61




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##### Table of Contents



Texas Gulf Coast Processing Segment Gross
    Margin.
  Corporate Segment Gross Margin. mark-to-market
  Operations and Maintenance
    Expenses.
  Depreciation and Amortization.
  General and Administrative Expenses.
  Interest Expense. payment-in-kind payment-in-kind
 62




---



##### Table of Contents



General
    Trends and Outlook
          Impact of
    Inflation
   63




---



##### Table of Contents



Liquidity
    and Capital Resources
    Form S-3
  Off-Balance Sheet Arrangements.
  Capital Requirements. capital-intensive,
  
    maintenance capital expenditures, which are capital expenditures
    employed to replace partially or fully depreciated assets to
    maintain the existing operating capacity of our assets and to
    extend their useful lives, or other capital expenditures that
    are incurred in maintaining existing system volumes and related
    cash flows; and
    expansion capital expenditures such as those to acquire
    additional assets to grow our business, to expand and upgrade
    gathering systems, transmission capacity or processing plants
    and to construct or acquire new pipelines or processing plants.     64




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##### Table of Contents



Total Contractual Cash Obligations.
  Payment Due by PeriodTotal











More than 5Type of Obligation

Obligation


Within 1 Year


2-3 Years


4-5 Years


years(In thousands)Long-term debt

$
255,000


$



$



$



$
255,000Interest(1)


178,743



20,411



40,823



40,823



76,686Operating leases


7,781



2,432



3,211



1,851



287Total contractual cash
    obligations(1)

$
441,524


$
22,843


$
44,034


$
42,674


$
331,973     (1)
    
    These amounts exclude estimates of the effect of our interest
    rate swap contracts on our future interest obligations. As of
    December 31, 2006, the fair value of our interest rate swap
    contracts, which expire in July 2010, totaled $0.4 million.      Cash
    Flows.
    Year Ended December 31,2006


2005


2004(In thousands)Net cash provided by operating
    activities

$
91,679


$
280


$
17,697Net cash used in investing
    activities


(70,291
)


(491,708
)


(8,919
)Net cash (used in) provided by
    financing activities


(7,201
)


509,710



(6,370
)Net increase in cash and cash
    equivalents


14,187



18,282



2,408Cash and cash equivalents at
    beginning of year


25,297



7,015



4,607Cash and cash equivalents at end
    of year

$
39,484


$
25,297


$
7,015  65




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##### Table of Contents



Operating:
  Year Ended December 31,2006


2005


2004(In thousands)Net income (loss)

$
65,114


$
30,352


$
(915
)Depreciation and amortization


36,455



22,775



9,287Equity in earnings from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)Deferred equity compensation,
    unrealized gain and other


2,086



1,309



(8
)Non-cash interest expense










17,132Cash used in working capital


(10,679
)


(53,229
)


(7,380
)Net cash provided by operating
    activities

$
91,679


$
280


$
17,697         Investing: 11-mile 8-mile rights-of-way
   66




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##### Table of Contents



Financing:
      Cash Distributions and Reserves:
  Description
    of Our Indebtedness
    Credit Ratings.
  Senior Secured Revolving Credit Facility.
   67




---



##### Table of Contents




    EBITDA to interest expense of not less than 3.0 to 1.0;
    total debt to EBITDA of not more than 5.0 to 1.0 (with no future
    reductions) with the option to increase the total debt to EBITDA
    ratio to not more than 5.5 to 1.0 for a period of up to nine
    months following an acquisition or a series of acquisitions
    totaling $50 million in a
    12-month
    period (subject to an increased applicable interest rate margin
    and commitment fee rate).            
    failure to pay any principal when due or any interest, fees or
    other amount within certain grace periods;
    failure to perform or otherwise comply with the covenants in the
    credit agreement or other loan documents, subject, in certain
    instances, to certain grace periods;
    default on the payment of any other indebtedness in excess of
    $5 million or any default in the performance of any
    obligation or condition with respect to such indebtedness beyond
    the applicable grace period if the effect of the default is to
    permit or cause the acceleration of the indebtedness;
    bankruptcy or insolvency events involving us or our subsidiaries;
    the entry of, and failure to pay, one or more adverse judgments
    in excess of $5 million against which enforcement
    proceedings are brought or that are not stayed pending
    appeal; and
    a change of control (as defined in the Credit Facility). 68




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##### Table of Contents



Senior Notes.
         69




---



##### Table of Contents



Year

Percentage2011


104.0625%2012


102.7083%2013


101.3542%2014 and thereafter


100.0000%       
    sell assets;
    pay distributions on, redeem or repurchase our units or redeem
    or repurchase our subordinated debt;
    make investments;
    incur or guarantee additional indebtedness or issue preferred
    units;
    create or incur certain liens;
    enter into agreements that restrict distributions or other
    payments from our restricted subsidiaries to us;
    consolidate, merge or transfer all or substantially all of our
    assets;
    engage in transactions with affiliates;
    create unrestricted subsidiaries; and
    enter into sale and leaseback transactions.    Recent
    Accounting Pronouncements
  Share-Based Payment. Share-Based
    Payment, Accounting for Stock
    Issued to Employees,
     70




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##### Table of Contents



Accounting Changes and Error Corrections. Accounting Changes and Error Corrections.
  Accounting for Purchases and Sales of Inventory with the Same
    Counterparty. No. 04-13, Accounting for Purchases and Sales of Inventory with
    the Same Counterparty 04-13). 04-13, 04-13
  Accounting for Uncertainty in Income Taxes. , Accounting for Uncertainty
    in Income Taxes  An Interpretation of FASB Statement
    No. 109. Accounting for Income Taxes
  Accounting for Servicing of Financial
    Assets. Accounting for Servicing of
    Financial Assets  an amendment of FASB Statement
    No. 140, available-for-sale
  Fair Value Measurements. Fair Value
    Measurements.
 71




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##### Table of Contents



Defined Benefit Pension and Other Postretirement
    Plans. Employers Accounting for
    Defined Benefit Pension and Other Postretirement
    Plans  an amendment of FASB Statements No. 87,
    88, 106, and 132(R).
  Fair Value Option for Financial Assets and Financial
    Liabilities. The Fair Value Option for
    Financial Assets and Financial Liabilities,
  Quantifying Misstatements in Current Year Financial
    Statements. Considering the Effects of Prior Year Misstatements
    When Quantifying Misstatements in Current Year Financial
    Statements,
  Critical
    Accounting Policies and Estimates
    Impairment of Long-Lived Assets. Accounting for the
    Impairment or Disposal of Long-Lived Assets,
    
    changes in general economic conditions in regions in which our
    assets are located; 72




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##### Table of Contents




    the availability and prices of raw natural gas supply;
    improvements in exploration and production technology;
    our ability to negotiate favorable sales agreements;
    our dependence on certain significant customers, producers,
    gatherers, and transporters of natural gas; and
    competition from other midstream service providers, including
    major energy companies.    Equity Method of Accounting.
  Revenue Recognition. agreed-upon
  Forward-Looking
    Statements
    
    our ability to successfully integrate any acquired assets or
    operations;
    the volatility of prices and market demand for natural gas and
    NGLs;
    our ability to continue to obtain new sources of natural gas
    supply;
    the ability of key producers to continue to drill and
    successfully complete and attach new natural gas supplies;
    our ability to retain our key customers;
    general economic conditions;
    the effects of government regulations and policies; and
    other financial, operational and legal risks and uncertainties
    detailed from time to time in our filings with the SEC.   73




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##### Table of Contents



Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk    Commodity
    Prices
  Commodity Price Risk.
  percentage-of-proceeds agreed-upon
  fee-for-service percentage-of-index
  process condition processing spread processing
    margin. processing margin conditioning mode
 74




---



##### Table of Contents



1-cent
  Commodity Price Hedging Activities.
  
    purchase put options or put spreads (purchase of a
    put and a sale of a put at a lower strike price) on WTI crude
    oil;
    purchase put or call options, enter into collars (purchase of a
    put together with the sale of a call) or call or put
    spreads ((i) purchase of a call and a sale of a call at a
    higher strike price or (ii) purchase of a put and a sale of
    a put at a lower strike price)
    and/or sell
    fixed for floating swaps on natural gas at Henry Hub, HSC or
    other highly liquid points relevant to our operations or to the
    operations of an entity to be acquired by us;
    purchase put options, enter into collars or put
    spreads (purchase of a put and a sale of a put at a lower
    strike price)
    and/or sell
    fixed for floating swaps on NGLs to which we, or an entity to be
    acquired by us, has direct price exposure, priced at Mt. Belvieu
    or Conway; and
    purchase put options and collars
    and/or sell
    fixed for floating swaps on the fractionation spread
    or the processing margin spread for any processing
    plant relevant to our operations or to the operations of an
    entity to be acquired by us.    
    maturities with respect to the purchase of any crude oil,
    natural gas, NGLs, fractionation spread or processing margin
    spread hedge instruments must be limited to five years from the
    date of the transaction;
    notional volume must not exceed 80% of the projected
    requirements or output, as applicable, for the hedged period
    with respect to (i) the purchase of crude oil or NGLs put
    options, (ii) the purchase of natural gas put or call
    options, (iii) the purchase of fractionation spread or
    processing margin spread put options or (iv) the entry into
    any crude oil, natural gas or NGLs spread options; and
    the aggregate volumetric exposure associated with swaps, collars
    and written calls relating to any product must not exceed 50% of
    the aggregate hedged position with respect to such product.    over-the-counter
 75




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##### Table of Contents



Accounting for Derivative Instruments and Hedging
    Activities
  Mid-Continent Operations Segment.
  Texas Gulf Coast Pipelines and Processing
    Segments.
    Purchased
    CenterPoint East Natural Gas Puts
  Put Strike


Put Volumes(Per MMBtu)


(MMBtu/d)


Fair Value2007

$
8.75



9,750


$
9,653,0002008

$
7.75



5,000


$
2,552,0002009

$
6.95



5,000


$
1,913,000   Purchased
    HSC Index Natural Gas Call Spreads
  Call Strike(Per MMBtu)


Call VolumesBought


Sold


(MMBtu/d)


Fair Value2007

$
8.00


$
10.00



11,400


$
1,221,0002008

$
8.15


$
10.00



9,400


$
1,670,0002009

$
7.75


$
10.00



8,000


$
1,667,0002010

$
7.35


$
10.00



7,100


$
1,512,0002011

$
6.95


$
10.00



7,100


$
1,519,000   Purchased Purity Ethane Puts and entered into swaps as listed
    below:
  Put


SwapStrike


Volumes





Price


Volumes(per gallon)


(Bbls/d)


Fair Value


(per gallon)


(Bbls/d)


Fair Value2007

$
0.6365



599


$
298,000


$
0.6525



599


$
(16,000
)2008

$
0.5700



607


$
135,000


$
0.5650



607


$
(1,229,000
)  76




---



##### Table of Contents



Purchased TET Propane Puts and entered into swaps as listed
    below:
  Put


SwapStrike


Volumes





Price


Volumes(per gallon)


(Bbls/d)


Fair Value


(per gallon)


(Bbls/d)


Fair Value2007

$
0.8930



2,575


$
1,174,000


$
0.9375



726


( $
579,000
)2007

$
0.9000



1,100


$
539,0002008

$
0.8360



2,594


$
1,263,000


$
0.8700



745


$
(1,936,000
)2008

$
0.8975



1,100


$
828,0002009

$
0.8725



2,200


$
1,832,0002010

$
0.8500



1,100


$
981,0002011

$
0.8265



1,100


$
1,028,000   Purchased Non-TET Isobutane Puts and entered into swaps as
    listed below:
  Put


SwapStrike


Volumes





Price


Volumes(per gallon)


(Bbls/d)


Fair Value


(per gallon)


(Bbls/d)


Fair Value2007

$
1.0675



620


$
195,000


$
1.1250



90


$
(121,000
)2007

$
1.0750



200


$
68,0002008

$
0.9900



622


$
187,000


$
1.0450



92


$
(316,000
)2008

$
1.0900



250


$
158,0002009

$
1.0600



450


$
305,0002010

$
1.0350



300


$
215,0002011

$
1.0205



300


$
241,000   Purchased Non-TET Normal-Butane Puts and entered into swaps
    as listed below:
  Put


SwapStrike


Volumes





Price


Volumes(per gallon)


(Bbls/d)


Fair Value


(per gallon)


(Bbls/d)


Fair Value2007

$
1.0650



803


$
258,000


$
1.1200



264


$
(227,000
)2007

$
1.0675



150


$
50,0002008

$
0.9875



810


$
203,000


$
1.0400



271


$
(763,000
)2008

$
1.0800



300


$
167,0002009

$
1.0525



700


$
391,0002010

$
1.0300



300


$
171,0002011

$
1.0205



300


$
192,000   Purchased WTI Crude Oil Puts as listed below:
  Put Strike


Put Volumes(per barrel)


(Bbls/d)


Fair Value2007

$
48.00



2,000


$
178,0002007

$
55.00



250


$
92,0002008

$
55.00



1,000


$
767,0002009

$
55.00



1,000


$
1,042,0002010

$
55.00



1,000


$
1,245,0002011

$
55.00



1,000


$
1,457,000   Interest
    Rates
   77




---



##### Table of Contents



Accounting for Derivative Instruments and Hedging
    Activities,
  Risk
    Management Oversight
    Credit
    Risk and Significant Customers
    Item 8.
    Financial
    Statements and Supplementary Data    Item 9.
    Changes
    in and Disagreements With Accountants on Accounting and
    Financial Disclosure   78




---



##### Table of Contents



Item 9A.
    Controls
    and Procedures  Managements
    Evaluation of Disclosure Controls and Procedures
    Managements
    Annual Report on Internal Control over Financial
    Reporting
  Rules 13a-15(f) Rules 13a-15(f))
    Changes
    in Internal Controls Over Financial Reporting
  Rule 13a-15(f)
 79




---



##### Table of Contents



MANAGEMENTS
    ANNUAL REPORT ON INTERNAL CONTROL
    OVER FINANCIAL REPORTING
    AS OF DECEMBER 31, 2006
  Rules 13a-15(f) 15d-15(f) Rules 13a-15(f))
      Rules 13a-15(f) 15d-15(f)
  /s/  John
    R.
    Eckel, Jr.Chairman
    of the Board of Directors and Chief Executive Officer

/s/  Matthew
    J. AssiffSenior
    Vice President and Chief Financial Officer    80




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
              81




---



##### Table of Contents



Deloitte &
    Touche LLP
    82




---



##### Table of Contents



Item 9B.
    Other
    Information   83




---



##### Table of Contents



PART III  Item 10.
    Directors
    and Executive Officers of the Registrant    Item 11.
    Executive
    Compensation    Item 12.
    Security
    Ownership of Certain Beneficial Owners and Management and
    Related Unitholder Matters    Item 13.
    Certain
    Relationships and Related Parties    Item 14.
    Principal
    Accountant Fees and Services   84




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##### Table of Contents



PART IV  Item 15.
    Exhibits
    and Financial Statement Schedules  (a)(1)
    and (2) Financial Statements
  page F-1.
  (a)(3)
    Exhibits
    Number

Description3
.1

Certificate of Formation of Copano
    Energy Holdings, L.L.C. (now Copano Energy, L.L.C.)
    (incorporated by reference to Exhibit 3.1 to Registration
    Statement on
    Form S-1
    filed July 30, 2004).3
.2

Certificate of Amendment to
    Certificate of Formation of Copano Energy Holdings, L.L.C. (now
    Copano Energy, L.L.C.) (incorporated by reference to
    Exhibit 3.2 to Registration Statement on
    Form S-1
    filed July 30, 2004).3
.3

Second Amended and Restated
    Limited Liability Company Agreement of Copano Energy, L.L.C.
    (incorporated by reference to Exhibit 3.3 to Post-Effective
    Amendment No. 1 to Registration Statement on
    Form S-1/A
    filed December 15, 2004).3
.4

Amendment No. 1 to Second
    Amended and Restated Limited Liability Company Agreement of
    Copano Energy, L.L.C. (incorporated by reference to
    Exhibit 3.4 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).3
.5

Amendment No. 2 to Second
    Amended and Restated Limited Liability Company Agreement of
    Copano Energy, L.L.C. (incorporated by reference to
    Exhibit 3.5 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).4
.1

Indenture dated as of
    February 7, 2006, among Copano Energy, L.L.C., Copano
    Energy Finance Corporation, the Guarantors parties thereto and
    U.S. Bank National Association, as trustee (incorporated by
    reference to Exhibit 4.1 to Current Report on
    Form 8-K
    filed February 8, 2006).4
.2

Rule 144A Global Note
    representing $224,500,000 principal amount of 8.125% Senior
    Notes due 2016 (incorporated by reference to Exhibit 4.2 to
    Current Report on
    Form 8-K
    filed February 8, 2006).4
.3

Regulation S Global Note
    representing $500,000 principal amount of 8.125% Senior Notes
    due 2016 (incorporated by reference to Exhibit 4.3 to
    Current Report on
    Form 8-K
    filed February 8, 2006).4
.4

Registration Rights Agreement
    dated as of February 7, 2006, among Copano Energy, L.L.C.,
    Copano Energy Finance Corporation, the Guarantors parties
    thereto and the Initial Purchasers named therein (incorporated
    by reference to Exhibit 4.4 to Current Report on
    Form 8-K
    filed February 8, 2006).4
.5

Class B Unit and Common Unit
    Purchase Agreement dated as of June 17, 2005 by and among
    Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company,
    RCH Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise
    Energy Infrastructure Corporation, Tortoise Energy Capital
    Corporation, Goldman, Sachs & Co., Energy Income and
    Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Alerian
    Opportunity Partners LP, Alerian Capital Partners LP, Strome
    HedgeCap, LP, Strome Alpha, LP and Strome Family Foundation
    (incorporated by reference to Exhibit 10.27 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).4
.6

Registration Rights Agreement made
    and entered into as of August 1, 2005, by and among Copano
    Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH
    Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise
    Energy Infrastructure Corporation, Tortoise Energy Capital
    Corporation, Goldman, Sachs & Co., Energy Income and
    Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Alerian
    Opportunity Partners LP, Alerian Capital Partners LP, Strome MLP
    Fund, L.P., Strome Alpha, LP and Strome Family Foundation
    (incorporated by reference to Exhibit 10.28 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).4
.7

Common Unit Purchase Agreement
    dated as of December 29, 2005, by and among Copano Energy,
    L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and
    Royal Bank of Canada (incorporated by reference to
    Exhibit 4.7 to Annual Report on
    Form 10-K
    filed March 16, 2006). 85




---



##### Table of Contents



Number

Description4
.8

Registration Rights Agreement
    dated as of December 29, 2005, by and among Copano Energy,
    L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and
    Royal Bank of Canada (incorporated by reference to
    Exhibit 4.7 to Annual Report on
    Form 10-K
    filed March 16, 2006).10
.1

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
.2

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
.3

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
.4

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
.5

Assignment and Assumption
    Agreement between Copano/Operations, Inc. and CPNO Services,
    L.P. effective January 1, 2005 with respect to Employment
    Agreement between Copano/Operations, Inc., R. Bruce Northcutt
    and the Copano Controlling Entities, as amended (incorporated by
    reference to Exhibit 10.10 to Annual Report on
    Form 10-K
    filed March 31, 2005).10
.6

Second Amendment to Employment
    Agreement between CPNO Services, L.P., R. Bruce Northcutt and
    the Copano Controlling Entities, effective March 1, 2005
    (incorporated by reference to Exhibit 10.10 to Annual
    Report on
    Form 10-K
    filed March 31, 2005).10
.7

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
.8

Assignment and Assumption
    Agreement between Copano/Operations, Inc. and CPNO Services,
    L.P. effective January 1, 2005 with respect to Employment
    Agreement between Copano/Operations, Inc. and James J.
    Gibson, III (incorporated by reference to
    Exhibit 10.10 to Annual Report on
    Form 10-K
    filed March 31, 2005).10
.9

First Amendment to Employment
    Agreement between CPNO Services, L.P. and James J.
    Gibson, III, effective March 1, 2005 (incorporated by
    reference to Exhibit 10.10 to Annual Report on
    Form 10-K
    filed March 31, 2005).10
.10

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
.11

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
.12

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
.13

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
.14

Form of Grant of Options
    (incorporated by reference to Exhibit 10.17 to Quarterly
    Report on
    Form 10-Q
    filed December 21, 2004).10
.15

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
.16

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). 86




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##### Table of Contents



Number

Description10
.17

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
.18

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
.19

2005 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed March 2, 2005).10
.20

Unitholder Voting Agreement dated
    as of August 1, 2005 by and among Copano Partners Trust,
    MBP III AIV, L.P., MBP Onapoc Holdings LLC, R. Bruce
    Northcutt and Matthew J. Assiff (incorporated by reference to
    Exhibit 10.29 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.21

Credit Agreement dated as of
    August 1, 2005 among Copano Energy, L.L.C., as the
    Borrower, Bank of America, N.A., as Administrative Agent and L/C
    Issuer, Comerica Bank and U.S. Bank National Association,
    as Co-Syndication Agents, Bank of Scotland and Fortis Capital
    Corp., as Co-Documentation Agents and The Other Lenders Party
    Hereto and Banc of America Securities LLC, as Sole Lead Arranger
    and Sole Book Manager (incorporated by reference to
    Exhibit 10.30 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.22

Bridge Loan Agreement dated as of
    August 1, 2005 among Copano Energy, L.L.C., as the
    Borrower, Banc of America Bridge LLC, as Administrative Agent
    and The Other Lenders Party Hereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Book Manager
    (incorporated by reference to Exhibit 10.31 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).10
.23

Employment Agreement between CPNO
    Services, L.P. and John A. Raber dated as of August 1, 2005
    (incorporated by reference to Exhibit 10.32 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).10
.24

Employment Agreement between
    ScissorTail Energy, L.L.C. and Bruce Roderick dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.33 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.25

Employment Agreement between
    ScissorTail Energy, L.L.C. and Sharon Robinson dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.34 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.26

Employment Agreement between
    ScissorTail Energy, L.L.C. and Thomas Coleman dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.35 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.27

Employment Agreement between
    ScissorTail Energy, L.L.C. and Lee E. Fiegener dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.36 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.28

Form of Unit Option Grant under
    the Copano Energy, L.L.C. Long-Term Incentive Plan (ScissorTail
    Energy, LLC Officers) (incorporated by reference to
    Exhibit 10.37 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.29

Form of Restricted Unit Grant
    under the Copano Energy, L.L.C. Long-Term Incentive Plan
    (ScissorTail Energy, LLC Officers) (incorporated by reference to
    Exhibit 10.38 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.30

Form of Indemnification Agreement
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed November 2, 2005).10
.31

First Amendment to Copano Energy,
    L.L.C. Long-Term Incentive Plan dated October 27, 2005
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed November 2, 2005).10
.32

Purchase Agreement dated as of
    January 31, 2006, among Copano Energy, L.L.C., Copano
    Energy Finance Corporation, the Guarantors parties thereto and
    the Initial Purchasers named therein (incorporated by reference
    to Exhibit 10.1 to Current Report on
    Form 8-K
    filed February 8, 2006).10
.33

2006 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed February 21, 2006).10
.34

Amended and Restated Gas
    Processing Contract entered into as of February 1, 2006,
    between Kinder Morgan Texas Pipeline, L.P. and Copano
    Processing, L.P. (incorporated by reference to Exhibit 10.1
    to Quarterly Report on
    Form 10-Q
    filed May 10, 2006). 87




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##### Table of Contents



Number

Description10
.35

First Amendment to Credit
    Agreement dated as of January 26, 2006 among Copano Energy,
    L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and the other Lenders party thereto
    (incorporated by reference to Exhibit 10.2 to Quarterly
    Report on
    Form 10-Q
    filed May 10, 2006).10
.36

Form of Grant of Restricted Units
    (Directors) (incorporated by reference to Exhibit 10.3 to
    Current Report on
    Form 8-K
    filed May 30, 2006).10
.37

Form of Grant of Options
    (Employees) (incorporated by reference to Exhibit 10.2 to
    Current Report on
    Form 8-K
    filed May 30, 2006).10
.38

Form of Grant of Restricted Units
    (Employees) (incorporated by reference to Exhibit 10.4 to
    Current Report on
    Form 8-K
    filed May 30, 2006).10
.39

Second Amendment to Copano Energy,
    L.L.C. Long-Term Incentive Plan dated May 25, 2006
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed May 30, 2006).10
.40

Loan Agreement dated as of
    September 29, 2006, among Copano Energy, L.L.C., as the
    Borrower, Banc of America Bridge LLC, as Administrative Agent,
    and The Other Lenders Party Hereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Lead Manager
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed October 5, 2006).10
.41

Second Amendment to Credit
    Agreement dated as of September 20, 2006 among Copano
    Energy, L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and the other Lenders party thereto
    (incorporated by reference to Exhibit 10.1 to Quarterly
    Report on
    Form 10-Q
    filed November 9, 2006).10
.42

Form of Grant of Restricted Units
    (Directors) (incorporated by reference to Exhibit 10.1 to
    Current Report on
    Form 8-K
    filed November 20, 2006).10
.43

Independent Director Compensation
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed November 20, 2006).10
.44

Amended and Restated Loan
    Agreement dated as of January 12, 2007, among Copano
    Energy, L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and L/C Issuer, JPMorgan Chase Bank, N.A.
    and Wachovia Bank, National Association, as Co-Syndication
    Agents and The Other Lenders Party thereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Book Manager
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed January 19, 2007).10
.45

2007 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed February 20, 2007).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.     *
    
    Filed herewith.
    
    Portions of this exhibit have been omitted pursuant to a request
    for confidential treatment.  (b)
    Exhibits   88




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##### Table of Contents



SIGNATURES
      By:
    /s/  John
    R. Eckel, Jr.     By:
    /s/  Matthew
    J. Assiff       Signature

Title

Date/s/  John
    R.
    Eckel, Jr.John
    R. Eckel, Jr.

Chairman of the Board of Directors
    and Chief Executive Officer (Principal Executive Officer)

March 16, 2007/s/  Matthew
    J. AssiffMatthew
    J. Assiff

Senior Vice President and Chief
    Financial Officer (Principal Financial Officer)

March 16, 2007/s/  Lari
    ParadeeLari
    Paradee

Vice President and Controller
    (Principal Accounting Officer)

March 16, 2007/s/  James
    G. CrumpJames
    G. Crump

Director

March 16, 2007/s/  Ernie
    L. DannerErnie
    L. Danner

Director

March 16, 2007/s/  Michael
    L. JohnsonMichael
    L. Johnson

Director

March 16, 2007/s/  Scott
    A.
    GriffithsScott
    A. Griffiths

Director

March 16, 2007/s/  T.
    William
    PorterT.
    William Porter

Director

March 16, 2007William
    L. Thacker

Director

March 16, 2007  89




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##### Table of Contents



COPANO
    ENERGY, L.L.C.
  INDEX TO
    FINANCIAL STATEMENTS
  PageCopano Energy, L.L.C. and
    Subsidiaries Consolidated Financial Statements:Report of
    Independent Registered Public Accounting Firm


F-2Consolidated
    Balance Sheets as of December 31, 2006 and 2005


F-3Consolidated
    Statements of Operations for the years ended December 31,
    2006, 2005 and 2004


F-4Consolidated
    Statements of Cash Flows for the years ended December 31,
    2006, 2005 and 2004


F-5Consolidated
    Statements of Members Capital and Comprehensive Income
    (Loss) for the years ended December 31, 2006, 2005 and
    2004


F-6Notes to
    Consolidated Financial Statements


F-7Webb/Duval Gatherers Financial
    Statements:Report of
    Independent Registered Public Accounting Firm


F-47Unaudited Balance
    Sheets as of December 31, 2006 and 2005


F-48Statements of
    Operations for the years ended December 31, 2006
    (unaudited), 2005 (unaudited) and 2004


F-49Statements of Cash
    Flows for the years ended December 31, 2006 (unaudited),
    2005 (unaudited) and 2004


F-50Statements of
    Partners Capital for the years ended December 31,
    2006 (unaudited), 2005 (unaudited) and 2004


F-51Notes to Financial
    Statements


F-52  F-1




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM   
          Internal Control 
    Integrated Framework
  Deloitte &
    Touche LLP
    
 F-2




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    BALANCE SHEETS
  December 31,2006


2005(In thousands,except unit information)ASSETSCurrent assets:Cash and cash equivalents

$
39,484


$
25,297Accounts receivable, net


66,416



83,297Accounts receivable from affiliates


679



Risk management assets


13,973



10,067Prepayments and other current
    assets


3,166



2,474Total current assets


123,718



121,135Property, plant and equipment, net


566,927



532,320Intangible assets, net


93,372



97,551Investment in unconsolidated
    affiliates


19,378



7,901Risk management assets


23,826



24,778Other assets, net


11,837



9,065Total assets

$
839,058


$
792,750LIABILITIES AND MEMBERS
    CAPITALCurrent liabilities:Accounts payable

$
91,545


$
96,001Accounts payable to affiliates


123



189Notes payable


1,495



1,272Other current liabilities


12,559



10,970Total current liabilities


105,722



108,432Long-term debt


255,000



398,000Risk management and other
    noncurrent liabilities


5,750



4,515Commitments and contingencies
    (Note 14)Members capital:Common units, no par value,
    17,595,295 units and 14,100,508 units issued and
    outstanding as of December 31, 2006 and 2005, respectively


480,797



297,592Subordinated units, no par value,
    3,519,126 units issued and outstanding as of
    December 31, 2006 and 2005


10,379



10,379Paid-in capital


10,585



4,068Accumulated earnings (deficit)


2,918



(14,941
)Deferred compensation






(3,949
)Other comprehensive loss


(32,093
)


(11,346
)472,586



281,803Total liabilities and
    members capital

$
839,058


$
792,750    F-3




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    STATEMENTS OF OPERATIONS
  Year Ended December 31,2006


2005


2004(In thousands,except per unit information)Revenue:Natural gas sales

$
447,251


$
496,551


$
262,317Natural gas sales 
    affiliates


803



355



557Natural gas liquids sales


369,892



224,695



161,570Transportation, compression and
    processing fees


16,200



15,079



11,295Transportation, compression and
    processing fees  affiliates


32



31



75Other


26,094



11,032



1,842Total revenue


860,272



747,743



437,656Costs and expenses:Cost of natural gas and natural gas
    liquids


665,655



636,461



381,615Cost of natural gas and natural gas
    liquids  affiliates


3,503



4,854



2,465Transportation


2,668



1,862



1,583Transportation 
    affiliates


358



475



492Operations and maintenance


32,484



18,459



12,486Depreciation and amortization


31,993



17,052



7,287General and administrative


26,535



18,156



9,217Taxes other than income


2,061



1,178



770Equity in earnings from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)Total costs and expenses


763,960



697,570



415,496Operating income


96,312



50,173



22,160Other income (expense):Interest and other income


1,706



640



85Interest and other financing costs


(32,904
)


(20,461
)


(23,160
)Net income (loss)

$
65,114


$
30,352


$
(915
)Basic net income (loss) per
    equivalent common unit:Net income (loss) per equivalent
    common unit

$
3.54


$
2.40


$
(0.35
)Weighted average number of
    equivalent common units


14,876



8,492



2,146Diluted net income (loss) per
    equivalent common unit:Net income (loss) per equivalent
    common unit

$
3.49


$
2.29


$
(0.35
)Weighted average number of
    equivalent common units


15,090



13,254



2,152Basic net income (loss) per
    subordinated unit:Net income (loss) per subordinated
    unit

$
3.54


$
2.40


$
(0.35
)Weighted average number of
    subordinated units


3,519



3,519



452Diluted net income (loss) per
    subordinated unit:Net income (loss) per subordinated
    unit

$
3.53


$
2.40


$
(0.35
)Weighted average number of
    subordinated units


3,519



3,519



452Basic net income per Class B
    unit:Net income per Class B unit

$



$
1.33


$
Weighted average number of
    Class B units






1,151



Diluted net income per Class B
    unit:Net income per Class B unit

$



$
0.77


$
Weighted average number of
    Class B units






1,151



    F-4




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    STATEMENTS OF CASH FLOWS
  Year Ended December 31,2006


2005


2004(In thousands)Cash Flows From Operating
    Activities:Net income (loss)

$
65,114


$
30,352


$
(915
)Adjustments to reconcile net income
    (loss) to net cash provided by operating activities:Depreciation and amortization


31,993



17,052



7,287Amortization of debt issue costs


4,462



5,723



2,000Equity in earnings from
    unconsolidated affiliates


(1,297
)


(927
)


(419
)Equity-based compensation


1,910



1,283



53Payment-in-kind interest on
    subordinated debt










814Payment-in-kind interest to
    preferred unitholders










6,508Accretion of preferred unitholders
    warrant value










9,405Accretion of subsidiary warrant
    value










405Other noncash items


176



26



(61
)Changes in assets and liabilities,
    net of acquisitions:Accounts receivable


16,880



(17,986
)


(11,440
)Accounts receivable from affiliates


(421
)


1,261



(370
)Prepayments and other current assets


1,372



2,771



85Risk management assets


(23,014
)


(42,635
)


Accounts payable


(6,801
)


19,658



5,591Accounts payable to affiliates


(66
)


62



(1,244
)Other current liabilities


1,371



(16,360
)


(2
)Net cash provided by operating
    activities


91,679



280



17,697Cash Flows From Investing
    Activities:Additions to property, plant and
    equipment


(49,033
)


(9,602
)


(8,085
)Additions to intangible assets


(1,237
)


(95,586
)


(505
)Acquisitions, net of cash acquired


(9,074
)


(384,154
)


(330
)Investment in unconsolidated
    affiliates


(10,438
)


(2,722
)


Escrow cash






1,001



1Other


(509
)


(645
)


Net cash used in investing
    activities


(70,291
)


(491,708
)


(8,919
)Cash Flows From Financing
    Activities:Repayments of long-term debt


(506,500
)


(94,000
)


(34,313
)Proceeds from long-term debt


363,500



435,000



40,000Repayment of short-term notes
    payable


(1,842
)


(1,207
)


Deferred financing costs


(7,035
)


(9,802
)


(2,063
)Repayment of subordinated debt










(15,199
)Repayments of other long-term
    obligations










(991
)Distributions to unitholders


(46,977
)


(23,366
)


(4,000
)Proceeds from initial public
    offering of common units, net of underwriting discounts and
    commissions of $8,050










106,950Proceeds from follow-on offering of
    common units, net of underwriting discounts and commissions of
    $7,216


162,725







Proceeds from private placement of
    common units


25,000



64,499



Proceeds from private placement of
    Class B units






135,503



Capital contributions from Pre-IPO
    Investors (Note 9)


4,607



4,068



Equity offering costs


(1,057
)


(1,074
)


(4,322
)Proceeds from option exercises


378



89



Redemption of preferred units










(78,077
)Payment of subscription receivable










143Distributions to special unitholders










(143
)Distributions to preferred
    unitholders










Redeem common units










(13,950
)Purchase warrants issued by
    subsidiary










(405
)Net cash (used in) provided by
    financing activities


(7,201
)


509,710



(6,370
)Net increase in cash and cash
    equivalents


14,187



18,282



2,408Cash and cash equivalents,
    beginning of year


25,297



7,015



4,607Cash and cash equivalents, end of
    year

$
39,484


$
25,297


$
7,015    F-5




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    STATEMENTS OF MEMBERS CAPITAL AND COMPREHENSIVE INCOME
    (LOSS)
  Common Special








Junior SpecialCommon


Class B


Subordinated





Common


Junior





Junior





Accumulated








Other





TotalNumber


Common


Number


Class B


Number


Subordinated


Number


Special


Number


Junior


Number


Special


Paid-in


Earnings


Subscription


Deferred


Comprehensive





Comprehensiveof Units


Units


of Units


Units


of Units


Units


of Units


Units


of Units


Units


of Units


Units


Capital


(Deficit)


Receivable


Compensation


Loss


Total


Income (Loss)(In thousands)Balance, December 31,
    2003


1,299


$
3,471






$







$




154


$
154



620


$
526



58


$
29


$
12,353


$
(17,012
)

$
(183
)

$



$



$
(662
)

$
Subscription receivable


























































183











183



Distribution to special unitholders






























(121
)














(22
)






















(143
)


Distribution to pre-IPO unitholders






















































(4,000
)














(4,000
)


Unit exchange


739



2,540











3,519



10,379



(154
)


(33
)


(620
)


(526
)


(58
)


(7
)


(12,353
)






















Issuance of common units to public


5,750



115,000































































115,000



Equity offering costs






(13,170
)






























































(13,170
)


Redeem common units from certain
    pre-IPO unitholders


(750
)


(13,950
)






























































(13,950
)


Issuance of restricted units


18



434























































(434
)










Equity-based compensation






























































13







13



Net loss






















































(915
)














(915
)


(915
)Comprehensive loss









































































$
(915
)Balance, December 31,
    2004


7,056



94,325











3,519



10,379































(21,927
)






(421
)






82,356



Capital contributions from Pre-IPO
    Investors


















































4,068



















4,068



Private placement of units


2,082



64,499



4,831



135,503























































200,002



Equity offering costs






(777
)






(858
)






















































(1,635
)


Conversion of Class B units
    into common units


4,831



134,645



(4,831
)


(134,645
)


























































Distributions to unitholders






















































(23,366
)














(23,366
)


Option exercises


5



89































































89



Issuance of restricted units


127



4,811























































(4,811
)










Equity-based compensation






























































1,283







1,283



Net income






















































30,352















30,352



30,352Unrealized loss-change in fair
    value of derivatives


































































(11,346
)


(11,346
)


(11,346
)Comprehensive income









































































$
19,006Balance, December 31,
    2005


14,101



297,592











3,519



10,379



























4,068



(14,941
)






(3,949
)


(11,346
)


281,803Capital contributions from Pre-IPO
    Investors


















































4,607



















4,607



Private placement of units


709



25,000































































25,000



Issuance of common units to public


2,875



169,941































































169,941



Equity offering costs






(8,165
)






























































(8,165
)


Distributions to unitholders






















































(47,255
)














(47,255
)


Option exercises


15



378































































378



Adoption of
    SFAS No. 123(R)-reversal of deferred compensation
    related to restricted units


(139
)


(3,949
)






















































3,949











Equity-based compensation


















































1,910



















1,910



Vested restricted units


34







































































Net income






















































65,114















65,114



65,114Derivative settlements reclassified
    to income


































































431



431



431Unrealized loss-change in fair
    value of derivatives


































































(21,178
)


(21,178
)


(21,178
)Comprehensive income









































































$
44,367Balance, December 31,
    2006


17,595


$
480,797






$




3,519


$
10,379






$







$







$



$
10,585


$
2,918


$



$



$
(32,093
)

$
472,586    F-6




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS
  Note 1 
    Organization
 Unless the context requires
    otherwise, references to Copano, we,
    our, us or like terms refer to Copano
    Energy, L.L.C. and its wholly-owned subsidiaries.
         Note 2 
    Summary of Significant Accounting Policies
 Basis
    of Presentation and Principles of Consolidation
     F-7




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
    Use of
    Estimates
    Cash
    and Cash Equivalents
    Concentration
    and Credit Risk
      Allowance
    for Doubtful Accounts
    Balance at





Write-Offs,


Balance atBeginning


Charged to


Net of


End ofof Period


Expense


Recoveries


PeriodYear ended December 31, 2006

$
64


$
42


$
(42
)

$
64Year ended December 31, 2005

$
356


$
(285
)

$
(7
)

$
64Year ended December 31, 2004

$
200


$
202


$
(46
)

$
356  F-8




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
  Property,
    Plant and Equipment
    Useful LivesPipelines and equipment


15-30 yearsGas processing plants and equipment


20-30 yearsOther property and equipment


3-7 years       Intangible
    Assets
  rights-of-way, 2007  2008  2009  2010
     2011 
  December 31,2006


2005Rights-of-way
    and easements, at cost

$
60,931


$
59,693Less accumulated amortization for
    rights-of-way
    and easements


(6,520
)


(3,969
)Contracts


42,444



42,444Less accumulated amortization for
    contracts


(4,009
)


(1,179
)Customer relationship


725



725Less accumulated amortization for
    customer relationship


(199
)


(163
)Intangible assets, net

$
93,372


$
97,551   rights-of-way rights-of-way
 F-9




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
  Other
    Assets
    Transportation
    and Exchange Imbalances
  mark-to-market
  Asset
    Retirement Obligations
  Accounting
    for Asset Retirement Obligations.
    Accounting for Conditional Asset
    Retirement Obligations, an interpretation of FASB Statement
    No. 143.
 F-10




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
    Revenue
    Recognition
  agreed-upon
      No. 04-13, Accounting for Purchases and Sales of Inventory with
    the Same Counterparty (Issue 04-13). Issue 04-13, Issue 04-13
  Year Ended December 31,2006


2005


2004(In thousands)Natural gas sales revenue:As reported

$
448,054


$
496,906


$
262,874As if presented net
    under
    Issue 04-13

$
448,054


$
464,798


$
262,874Cost of natural gas and natural
    gas liquids:As reported

$
669,158


$
641,315


$
384,080As if presented net
    under
    Issue 04-13

$
669,158


$
609,207


$
384,080     Derivatives
  Accounting for Derivative
    Instruments and Hedging Activities,
 F-11




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
        Accounting
    for Certain Financial Instruments with Characteristics of Both
    Liabilities and Equity
  Accounting for Certain Financial Instruments with
    Characteristics of Both Liabilities and
    Equity.
  Net
    Income (Loss) Per Unit
  Earnings Per Share, No. 03-6 (Issue 03-6), Participating Securities and the Two-Class Method
    under Financial Accounting Standards Board Statement
    No. 128  Issue 03-6
   F-12




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
    Year Ended December 31,2006


2005


2004(In thousands, except per unit information)Net income (loss)

$
65,114


$
30,352


$
(915
)Less net income attributable to
    subordinated units


(12,457
)


(8,446
)


159Less net income attributable to
    Class B units






(1,526
)


Net income (loss)
    available  basic common units


52,657



20,380



(756
)Net income reallocated from
    subordinated units


39



8,446



(159
)Net income reallocated from to
    Class B units






1,526



Net income (loss)
    available  diluted common units

$
52,696


$
30,352


$
(915
)Basic weighted average equivalent
    common units


14,876



8,492



2,146Dilutive weighted average
    equivalent common units**


15,090



13,254



2,152Basic net income (loss) per
    equivalent common unit

$
3.54


$
2.40


$
(0.35
)Diluted net income (loss) per
    equivalent common unit**

$
3.49


$
2.29


$
(0.35
)     **
    
    Our potentially dilutive common equity includes the following:  Year Ended December 31,2006


2005


2004(In thousands)Employee options


159



92



6Restricted units


55







   Share-Based
    Payment
  Share-Based Payment, Accounting
    for Stock Issued to Employees,
   F-13




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
     Note 3 
    New Accounting Pronouncements
 Accounting
    Changes and Error Corrections
  Accounting Changes and Error Corrections.
  Accounting
    for Servicing of Financial Assets
  Accounting for Servicing of Financial
    Assets  an amendment of FASB Statement
    No. 140, available-for-sale
  Fair
    Value Measurements
  Fair Value Measurements.
 F-14




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 3 
    New Accounting Pronouncements (Continued)
  Defined
    Benefit Pension and Other Postretirement Plans
  Employers Accounting for Defined Benefit Pension and
    Other Postretirement Plans  an amendment of FASB
    Statements No. 87, 88, 106, and 132(R).
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
  Quantifying
    Misstatements
  Considering the Effects of Prior Year Misstatements
    When Quantifying Misstatements in Current Year Financial
    Statements,
  Accounting
    for Uncertainty in Income Taxes-an Interpretation of FASB
    Statement No. 109
  Accounting
    for Uncertainty in Income Taxes-An Interpretation of FASB
    Statement No. 109. Accounting for Income
    Taxes
   Note 4 
    Acquisitions
 Acquisition
    of ScissorTail Energy, LLC
   F-15




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions (Continued)
        Purchase price for ScissorTail
    membership interests

$
500,000Estimated net working capital
    adjustments


(4,735
)Estimated acquisition costs


3,870Total purchase price for the
    ScissorTail Acquisition

$
499,135     Cash and cash equivalents

$
19,847Accounts receivable


28,265Prepayments and other current
    assets


1,817Property, plant and equipment


414,003Intangibles


95,134Other assets


2,090Accounts payable


(36,483
)Other current liabilities


(25,538
)$
499,135   rights-of-way
   F-16




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions (Continued)
    Year Ended December 31,2005


2004(unaudited, in thousands, except per unit information)Pro Forma Earnings Data:Revenue

$
933,030


$
689,881Costs and expenses

$
866,972


$
656,348Operating income

$
66,058


$
33,534Income (loss) before extraordinary
    items

$
34,825


$
(1,574
)Net income (loss)

$
34,825


$
(1,574
)Basic net income (loss) per
    equivalent unit:As reported equivalent units
    outstanding


9,643



2,599Pro forma units outstanding


13,241



16,761As reported net income (loss) per
    equivalent unit

$
2.31


$
(0.35
)Pro forma net income (loss) per
    equivalent unit

$
2.08


$
(0.09
)Diluted net income (loss) per
    equivalent unit:As reported equivalent units
    outstanding


13,254



2,604Pro forma units outstanding


16,852



16,761As reported net income (loss) per
    equivalent unit

$
2.29


$
(0.35
)Pro forma net income (loss) per
    equivalent unit

$
2.07


$
(0.09
)   Runge
    Gathering System
      F-17




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 5 
    Property, Plant, Equipment and Asset Retirement
    Obligations
    December 31,2006


2005Property, plant and equipment, at
    costPipelines and equipment

$
531,509


$
510,209Gas processing plant and equipment


77,556



50,564Construction in progress


18,386



8,445Office furniture and equipment


4,902



2,617632,353



571,835Less accumulated depreciation and
    amortization


(65,426
)


(39,515
)Property, plant and equipment, net

$
566,927


$
532,320   Asset retirement obligations. (i) rights-of-way
    Asset retirement obligation
    liability balance, December 31, 2004

$
Adoption of FIN 47 for
    conditional obligations


215Asset retirement obligation
    liability balance, December 31, 2005


215Asset retirement obligations
    incurred in 2006


106Accretion of FIN 47 for
    conditional obligations


19Asset retirement obligation
    liability balance, December 31, 2006

$
340    F-18




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 5 
    Property, Plant, Equipment and Asset Retirement Obligations
    (Continued)
    December 31,2005


2004(in thousands, except per unit information)Net income
    (loss)  as reported

$
30,352


$
(915
)Effect of implementation of
    FIN 47


126



(13
)Less net income attributable to
    subordinated unitholders


(8,148
)


Net income
    (loss)  basic  pro forma


22,330



(928
)Net income attributable to
    subordinated unitholders


8,148



Net income (loss)
    available  diluted  pro forma

$
30,478


$
(928
)Basic weighted average equivalent
    units


9,643



2,599Dilutive weighted average
    equivalent units


13,254



2,604Basic net income (loss) per
    equivalent unit  as reported

$
2.31


$
(0.35
)Basic net income (loss) per
    equivalent unit  pro forma

$
2.32


$
(0.36
)Diluted net income (loss) per
    equivalent unit  as reported

$
2.29


$
(0.35
)Diluted net income (loss) per
    equivalent unit  pro forma

$
2.30


$
(0.36
)     F-19




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 6 
    Investment in Unconsolidated Affiliates
      Webb/Duval
    Gatherers
 Summary Historical Financial Information
  Year Ended December 31,2006


2005


2004Operating revenue

$
5,961


$
6,809


$
4,605Operating expenses


(3,733
)


(4,837
)


(3,504
)Depreciation


(743
)


(702
)


(655
)Net income


1,485



1,270



446Ownership %


62.5
%


62.5
%


62.5
%928



793



278Copanos share of management
    fee charged to Webb Duval


120



120



120Amortization of difference between
    the carried investment and the underlying equity in net assets


21



21



21Equity in earnings from
    unconsolidated affiliate

$
1,069


$
934


$
419Distributions from unconsolidated
    affiliate

$



$



$
Current assets

$
4,595


$
3,378Noncurrent assets


8,104



8,032Current liabilities


(2,502
)


(2,701
)Noncurrent liabilities


(47
)


(44
)Net assets

$
10,150


$
8,665    F-20




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment in Unconsolidated Affiliates (Continued)
      Southern
    Dome, LLC
 Summary Historical Financial Information
  Year Ended December 31,2006


2005Operating revenue

$
6,105


$
1,289Operating expenses


(5,468
)


(1,296
)Depreciation


(497
)


(3
)Net income (loss)


140



(10
)Ownership %(1)


69.5
%


69.5
%97



(7
)Copanos share of management
    fee charged to Southern Dome


137



Amortization of difference between
    the carried investment and the underlying equity in net assets


(6
)


Equity in earnings (loss) from
    unconsolidated affiliate

$
228


$
(7
)Distributions from unconsolidated
    affiliate

$



$
Current assets

$
2,516


$
305Noncurrent assets


17,507



9,538Current liabilities


(2,189
)


(3,917
)Net assets

$
17,834


$
5,926     (1)
    
    Represents Copanos right to distributions from Southern
    Dome.  F-21




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 7 
    Long-Term Debt
    December 31,2006


2005Long-term debt:Credit Facility

$
30,000


$
228,000Senior Notes


225,000



Term Loan Facility






170,000Total

$
255,000


$
398,000   Senior
    Secured Revolving Credit Facility
         F-22




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
    
    EBITDA to interest expense of not less than 3.0 to 1.0;
    total debt to EBITDA of not more than 5.0 to 1.0 (with no future
    reductions) with the option to increase the total debt to EBITDA
    ratio to not more than 5.5 to 1.0 for a period of up to nine
    months following an acquisition or a series of acquisitions
    totaling $50 million in a
    12-month
    period (subject to an increased applicable interest rate margin
    and commitment fee rate).            
    failure to pay any principal when due or any interest, fees or
    other amount within certain grace periods;
    failure to perform or otherwise comply with the covenants in the
    credit agreement or other loan documents, subject, in certain
    instances, to certain grace periods;
    default on the payment of any other indebtedness in excess of
    $5 million or any default in the performance of any
    obligation or condition with respect to such indebtedness beyond
    the applicable grace period if the effect of the default is to
    permit or cause the acceleration of the indebtedness;
    bankruptcy or insolvency events involving us or our subsidiaries;
    the entry of, and failure to pay, one or more adverse judgments
    in excess of $5 million against which enforcement
    proceedings are brought or that are not stayed pending
    appeal; and
    a change of control (as defined in the Credit Facility).   F-23




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
        Senior
    Notes
         F-24




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
      Year

Percentage2011


104.0625
%2012


102.7083
%2013


101.3542
%2014 and thereafter


100.0000
%       
    sell assets;
    pay distributions on, redeem or repurchase our units or redeem
    or repurchase our subordinated debt;
    make investments;
    incur or guarantee additional indebtedness or issue preferred
    units;
    create or incur certain liens;
    enter into agreements that restrict distributions or other
    payments from our restricted subsidiaries to us;
    consolidate, merge or transfer all or substantially all of our
    assets;
    engage in transactions with affiliates;
    create unrestricted subsidiaries; and
    enter into sale and leaseback transactions.     F-25




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING BALANCE SHEET
  December 31, 2006


December 31, 2005Investment in

















Investment inGuarantor


Non-Guarantor














Guarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total


Parent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)ASSETSCurrent assets:Cash and cash equivalents

$
1,286


$



$
38,198


$



$



$
39,484


$
1,167


$
1


$
24,129


$



$



$
25,297Accounts receivable, net


32







66,384











66,416











83,297











83,297Accounts receivable from affiliates










53,673







(52,994
)


679























Intercompany receivable


24,908







(71,028
)






46,120







35,040







12,525







(47,565
)


Risk management assets










13,973











13,973











10,067











10,067Prepayments and other current assets


44







3,122











3,166



44







2,430











2,474Total current assets


26,270







104,322







(6,874
)


123,718



36,251



1



132,448







(47,565
)


121,135Property, plant and equipment, net


299







566,628











566,927



309







531,957







54



532,320Intangible assets, net










93,372











93,372











97,551











97,551Investment in unconsolidated
    affiliates










19,378



19,378



(19,378
)


19,378











7,901



7,901



(7,901
)


7,901Investment in consolidated
    subsidiaries


706,198















(706,198
)






658,687















(658,687
)


Risk management assets










23,826











23,826











24,778











24,778Other assets, net


8,577







3,260











11,837



6,004







3,061











9,065Total assets

$
741,344


$



$
810,786


$
19,378


$
(732,450
)

$
839,058


$
701,251


$
1


$
797,696


$
7,901


$
(714,099
)

$
792,750LIABILITIES AND
    MEMBERS/PARTNERS CAPITALCurrent liabilities:Accounts payable

$
434


$



$
91,111


$



$



$
91,545


$
165


$



$
95,836


$



$



$
96,001Accounts payable to affiliates










39,808







(39,685
)


123











189











189Intercompany payable


(26,291
)






(6,520
)






32,811







3,981







43,584







(47,565
)


Notes payable










1,495











1,495











1,272











1,272Other current liabilities


6,811







5,748











12,559



5,694







5,276











10,970Total current liabilities


(19,046
)






131,642







(6,874
)


105,722



9,840







146,157







(47,565
)


108,432Long-term debt


255,000



















255,000



398,000



















398,000Risk management and other
    noncurrent liabilities


711







5,039











5,750



262







4,253











4,515Members/Partners
    capital:Common units


480,797



















480,797



297,592



















297,592Subordinated units


10,379



















10,379



10,379



















10,379Paid-in capital


10,585



1



524,940



17,445



(542,386
)


10,585



4,068



1



585,800



7,265



(593,066
)


4,068Accumulated deficit


2,918



(1
)


181,258



1,933



(183,190
)


2,918



(14,941
)






72,832



636



(73,468
)


(14,941
)Deferred compensation


























(3,949
)


















(3,949
)Other comprehensive loss










(32,093
)










(32,093
)










(11,346
)










(11,346
)504,679







674,105



19,378



(725,576
)


472,586



293,149



1



647,286



7,901



(666,534
)


281,803Total liabilities and
    members/partners capital

$
741,344


$



$
810,786


$
19,378


$
(732,450
)

$
839,058


$
701,251


$
1


$
797,696


$
7,901


$
(714,099
)

$
792,750  F-26




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENT OF OPERATIONS
  For the Year Ended December 31, 2006


For the Year Ended December 31, 2005Investment in

















Investment inGuarantor


Non-Guarantor














Guarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total


Parent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Revenue:Natural gas sales

$



$



$
448,054


$



$



$
448,054


$



$



$
496,906


$



$



$
496,906Natural gas liquids sales










369,892











369,892











224,695











224,695Transportation, compression and
    processing fees










16,232











16,232











15,110











15,110Other










26,094











26,094











11,032











11,032Total revenue










860,272











860,272











747,743











747,743Costs and expenses:Cost of natural gas and natural gas
    liquids










669,158











669,158











641,315











641,315Transportation










3,026











3,026











2,337











2,337Operations and maintenance


917







31,567











32,484



66







18,393











18,459Depreciation and amortization


66







31,927











31,993



66







16,986











17,052General and administrative


9,296



1



17,238











26,535



5,486







12,670











18,156Taxes other than income










2,061











2,061











1,178











1,178Equity in earnings from
    unconsolidated affiliates










(1,297
)


(1,297
)


1,297



(1,297
)










(927
)


(927
)


927



(927
)Total costs and expenses


10,279



1



753,680



(1,297
)


1,297



763,960



5,618







691,952



(927
)


927



697,570Operating (loss) income


(10,279
)


(1
)


106,592



1,297



(1,297
)


96,312



(5,618
)






55,791



927



(927
)


50,173Other income (expense):Interest and other income










1,706











1,706



3







1,023







(386
)


640Interest and other financing costs


(33,207
)






303











(32,904
)


(16,848
)






(3,999
)






386



(20,461
)(Loss) income before equity in
    earnings from consolidated subsidiaries


(43,486
)


(1
)


108,601



1,297



(1,297
)


65,114



(22,463
)






52,815



927



(927
)


30,352Equity in earnings from
    consolidated subsidiaries


108,600















(108,600
)






52,815















(52,815
)


Net income (loss)

$
65,114


$
(1
)

$
108,601


$
1,297


$
(109,897
)

$
65,114


$
30,352


$



$
52,815


$
927


$
(53,742
)

$
30,352  F-27




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENT OF OPERATIONS
  For the Year Ended December 31, 2004Investment inGuarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Revenue:Natural gas sales

$



$



$
262,874


$



$



$
262,874Natural gas liquids sales










161,570











161,570Transportation, compression and
    processing fees










11,370











11,370Other










1,842











1,842Total revenue










437,656











437,656Costs and expenses:Cost of natural gas and natural gas
    liquids










384,080











384,080Transportation










2,075











2,075Operations and maintenance










12,486











12,486Depreciation and amortization


66







7,221











7,287General and administrative


2,106







7,111











9,217Taxes other than income










770











770Equity in earnings from
    unconsolidated affiliates










(419
)


(419
)


419



(419
)Total costs and expenses


2,172







413,324



(419
)


419



415,496Operating (loss) income


(2,172
)






24,332



419



(419
)


22,160Other income (expense):Interest and other income


7







665







(587
)


85Interest and other financing costs


(17,643
)






(6,104
)






587



(23,160
)(Loss) income before equity in
    earnings from consolidated subsidiaries


(19,808
)






18,893



419



(419
)


(915
)Equity in earnings from
    consolidated subsidiaries


18,893















(18,893
)


Net income (loss)

$
(915
)

$



$
18,893


$
419


$
(19,312
)

$
(915
)  F-28




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENT OF CASH FLOWS
  For the Year Ended December 31, 2006


For the Year Ended December 31, 2005Investment in

















Investment inGuarantor


Non-Guarantor














Guarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total


Parent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Cash Flows From Operating
    Activities:Net cash (used in) provided by
    operating activities

$
(55,791
)

$
(1
)

$
147,471


$



$



$
91,679


$
(47,292
)

$



$
47,572


$



$



$
280Cash Flows From Investing
    Activities:Additions to property, plant and
    equipment


409







(49,442
)










(49,033
)










(9,602
)










(9,602
)Additions to intangible assets










(1,237
)










(1,237
)










(95,586
)










(95,586
)Acquisitions, net of cash acquired










(9,074
)










(9,074
)










(384,154
)










(384,154
)Investment in unconsolidated
    affiliate










(10,438
)


(10,438
)


10,438



(10,438
)










(2,722
)


(2,722
)


2,722



(2,722
)Escrow cash


































1,001











1,001Investment in consolidated
    subsidiaries


(1,240
)














1,240







(548,662
)














548,662



Distributions from consolidated
    subsidiaries


62,100















(62,100
)






48,024















(48,024
)


Other










(509
)










(509
)










(645
)










(645
)Net cash provided by (used in)
    investing activities


61,269







(70,700
)


(10,438
)


(50,422
)


(70,291
)


(500,638
)






(491,708
)


(2,722
)


503,360



(491,708
)Cash Flows From Financing
    Activities:Repayments of long-term debt


(506,500
)


















(506,500
)


(37,000
)






(57,000
)










(94,000
)Proceeds from long-term debt


363,500



















363,500



435,000



















435,000(Repayment of) proceeds from
    intercompany debt


























(19,011
)






19,011











Deferred financing costs


(7,035
)


















(7,035
)


(9,735
)






(67
)










(9,802
)Repayment of short-term notes
    payable










(1,842
)










(1,842
)










(1,207
)










(1,207
)Distributions to unitholders


(46,977
)


















(46,977
)


(23,366
)


















(23,366
)Proceeds from follow-on offering of
    common units, net of underwriting discounts and commissions of
    $7,216


162,725



















162,725























Proceeds from private placement of
    common units


25,000



















25,000



64,499



















64,499Proceeds from private placement of
    Class B units


























135,503



















135,503Capital contributions from Pre-IPO
    Investors


4,607



















4,607



4,068



















4,068Equity offering costs


(1,057
)


















(1,057
)


(1,074
)


















(1,074
)Proceeds from option exercises


378



















378



89



















89Contributions from parent










1,240



10,438



(11,678
)










1



548,661



2,722



(551,384
)


Distributions to parent










(62,100
)






62,100















(48,024
)






48,024



Net cash (used in) provided by
    financing activities


(5,359
)






(62,702
)


10,438



50,422



(7,201
)


548,973



1



461,374



2,722



(503,360
)


509,710Net increase (decrease) in cash and
    cash equivalents


119



(1
)


14,069











14,187



1,043



1



17,238











18,282Cash and cash equivalents,
    beginning of year


1,167



1



24,129











25,297



124







6,891











7,015Cash and cash equivalents, end of
    year

$
1,286


$



$
38,198


$



$



$
39,484


$
1,167


$
1


$
24,129


$



$



$
25,297  F-29




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENT OF CASH FLOWS
  For the Year Ended December 31, 2004Investment inGuarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Cash Flows From Operating
    Activities:Net cash provided by operating
    activities

$
1,641


$



$
16,056


$



$



$
17,697Cash Flows From Investing
    Activities:Additions to property, plant and
    equipment










(8,085
)










(8,085
)Additions to intangible assets










(505
)










(505
)Acquisitions










(330
)










(330
)Escrow cash










1











1Note payable to parent










(19,011
)






19,011



Investment in consolidated
    subsidiaries


(57,535
)














57,535



Distributions from consolidated
    subsidiaries


31,156















(31,156
)


Net cash (used in) provided by
    investing activities


(26,379
)






(27,930
)






45,390



(8,919
)Cash Flows From Financing
    Activities:Repayments of long-term debt










(34,313
)










(34,313
)Proceeds from long-term debt










40,000











40,000Repayment of subordinated debt










(15,199
)










(15,199
)Repayments of other long-term
    obligations










(991
)










(991
)Proceeds from intercompany debt


19,011















(19,011
)


Deferred financing costs










(2,063
)










(2,063
)Distributions to unitholders


(4,000
)


















(4,000
)Payment of subscription receivable


143



















143Distributions to special unitholders


(143
)


















(143
)Proceeds from IPO of common units,
    net of underwriting discounts and commissions of $8,505


106,950



















106,950Redemption of preferred units


(78,077
)


















(78,077
)Redeem common units


(13,950
)


















(13,950
)Purchase warrants issued by
    subsidiary










(405
)










(405
)Equity offering costs


(5,121
)






799











(4,322
)Contributions from parent










57,535







(57,535
)


Distributions to parent










(31,156
)






31,156



Net cash provided by (used in)
    financing activities


24,813







14,207







(45,390
)


(6,370
)Net increase in cash and cash
    equivalents


75







2,333











2,408Cash and cash equivalents,
    beginning of year


49







4,558











4,607Cash and cash equivalents, end of
    year

$
124


$



$
6,891


$



$



$
7,015  F-30




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  Unsecured
    Term Loan
      Term
    Loan Facility
      CPG
    Credit Agreement
      Scheduled
    Maturities of Long-Term Debt
    PrincipalYear

Amount2007

$
2008


2009


2010


2011


Thereafter


255,000$
255,000  F-31




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 8 
    Redeemable Preferred Units
          Note 9 
    Members Capital
  Common
    Units, Class B and Subordinated Units After the
    IPO
  one-for-one two-for-one
 F-32




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Members Capital (Continued)
    Form S-3,
  Form S-3,
  Form S-3,
  one-for-one
   F-33




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Members Capital (Continued)
    Restricted
    Units
      Distributions
  one-for-one
  DistributionQuarter Ended

Per Unit


Date Declared


Record Date


Payment Date


AmountDecember 31, 2004

$
0.20
(a)


January 18, 2005



February 1, 2005



February 14, 2005


$
2,115,000March 31, 2005


0.42



April 18, 2005



May 2, 2006



May 13, 2005



4,450,000June 30, 2005


0.45
(b)


July 15, 2005



August 1, 2005



August 15, 2005



7,819,000September 30, 2005


0.50



October 17, 2005



November 1, 2005



November 14, 2005



8,449,000December 31, 2005


0.55



January 18, 2006



February 1, 2006



February 14, 2006



10,081,000March 31, 2006


0.60



April 18, 2006



May 1, 2006



May 15, 2006



11,000,000June 30, 2006


0.675



July 19, 2006



August 1, 2006



August 14, 2006



12,400,000September 30, 2006


0.75



October 18, 2006



November 1, 2006



November 14, 2006



13,800,000December 31, 2006


0.80



January 18, 2007



February 1, 2007



February 14, 2007



17,025,000     (a)
    
    The distribution for the quarter ended December 31, 2004
    reflected a pro rata portion of our $0.40 per unit MQD,
    covering the period from the November 15, 2004 closing of
    our IPO through December 31, 2004.(b)
    
    Includes a concurrent quarterly distribution of $0.495 per
    unit with respect to 4,830,758 Class B units issued in
    connection with the closing of the ScissorTail Acquisition. F-34




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Members Capital (Continued)
  two-for-one
  Unit
    Options
  and/or and/or
    Accounting
    for Equity-Based Compensation
  Accounting for
    Stock-Based Compensation. Restricted Common Units Unit
    Options
 F-35




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Members Capital (Continued)
   Unit Options.
  2006


2005


2004Number of


Weighted


Number of


Weighted


Number of


WeightedUnits


Average


Units


Average


Units


AverageUnderlying


Exercise


Underlying


Exercise


Underlying


ExerciseOptions


Price


Options


Price


Options


PriceOutstanding at beginning of period


491,110


$
30.18



200,000


$
20.00







Granted


157,745



47.04



309,110



36.51



200,000


$
20.00Exercised


(15,032
)


25.16



(4,440
)


20.00







Forfeited


(27,570
)


36.01



(13,560
)


27.75







Outstanding at end of period


606,253


$
34.31



491,110


$
30.18



200,000


$
20.00Aggregate intrinsic value at end
    of period

$
15,337,000Weighted average remaining
    contractual term


8.6 yearsExercisable Options:Outstanding at end of period


118,134


$
27.61



37,688


$
20.40







Aggregate intrinsic value at end
    of period

$
3,779,000Weighted average remaining
    contractual term


8.2 yearsWeighted average fair value of
    option granted





$
6.19






$
5.14






$
1.44Options expected to vest:At end of period


545,628


$
34.31Aggregate intrinsic value at end
    of period

$
13,803,000Weighted average remaining
    contractual term


8.6       Year Ended December 31,2006


2005


2004Weighted average exercise price

$
47.04


$
36.51


$
20.00Expected volatility


21.3-22.5
%


24.5-26.9
%


17.9
%Distribution yield


5.97-6.04
%


6.27-6.51
%


6.18
%Risk-free interest rate


4.33-5.14
%


3.74-4.59
%


3.12
%Expected term (in years)


6.5



7



7Weighted average grant-date fair
    value of options granted

$
6.19


$
5.14


$
1.44Total intrinsic value of options
    exercised

$
412,000


$
82,000


$
    F-36




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Members Capital (Continued)
   Restricted Units.
  2006


2005


2004Weighted Average





Weighted Average





Weighted AverageNumber of


Grant-Date Fair


Number of


Grant-Date Fair


Number of


Grant-Date FairRestricted Units


Value


Restricted Units


Value


Restricted Units


ValueOutstanding at beginning of period


139,118


$
36.59



18,000


$
24.12







Granted


60,270



49.03



129,470



37.74



18,000


$
24.12Vested


(34,653
)


34.76



(6,262
)


24.81







Forfeited


(6,767
)


38.03



(2,090
)


36.19







Outstanding at end of period


157,968


$
41.67



139,118


$
36.59



18,000


$
24.12         Year Ended December 31,2005


2004Net income (loss), as reported

$
30,352


$
(915
)Add: Equity-based compensation
    included in net income


1,282



13Less: Equity-based employee
    compensation expense determined under SFAS No. 123(R)


(893
)


(18
)Pro forma net income (loss)

$
30,741


$
(920
)Net income (loss) per unit:Basic  as reported

$
2.31


$
(0.35
)Basic  pro forma

$
2.34


$
(0.35
)Diluted  as reported

$
2.29


$
(0.35
)Diluted  pro forma

$
2.32


$
(0.35
)    Note 10 
    Related Party Transactions
  Operations
    Services
   F-37




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 10 
    Related Party Transactions (Continued)
      Natural
    Gas and Related Transactions
         F-38




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 10 
    Related Party Transactions (Continued)
   Other
          Note 11 
    Customer Information
    Percentage
    of Consolidated Revenue (1)
  Year Ended December 31,Customer

Segment

2006


2005


2004ONEOK Energy Services, L.P.

Mid-Continent Operations


21
%


14
%


Enterprise Products Operating,
    L.P.

Texas Gulf Coast
    Pipelines/Processing


19
%






14
%KMTP

Texas Gulf Coast
    Pipelines/Processing


14
%


26
%


27
%ONEOK Hydrocarbon, L.P.

Mid-Continent Operations


13
%






Dow Hydrocarbons and Resources
    Inc.

Texas Gulf Coast Processing






12
%


22
%   Percentage
    of Consolidated Cost of Goods Sold (1)
  Year Ended December 31,Producers

Segment

2006


2005


2004New Dominion LLC

Mid-Continent Operations


19
%


8
%


Altex Resources, Inc.

Mid-Continent Operations


5
%






Noble Energy, Inc.

Texas Gulf Coast Pipelines






7
%


11
%KMTP

Texas Gulf Coast Pipelines










8
%   Percentage
    of Consolidated Accounts Receivable (1)
  Year EndedDecember 31,Customer

Segment

2006


2005


2004ONEOK Energy Services, L.P.

Mid-Continent Operations


25
%


27
%


ONEOK Hydrocarbon, L.P.

Mid-Continent Operations


13
%






KMTP

Texas Gulf Coast
    Pipelines/Processing


12
%


23
%


31
%Enterprise Products Operating,
    L.P.

Texas Gulf Coast Processing


11
%






CenterPoint Energy, Inc.

Texas Gulf Coast Pipelines






10
%


Dow Hydrocarbons and Resources
    Inc.

Texas Gulf Coast Processing










29
%Entergy Gulf States, Inc.

Texas Gulf Coast Pipelines










11
%     (1)
    
    Percentages are not provided for periods for which the customer
    or producer is not considered significant. F-39




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 12 
    Risk Management Activities
    Commodity
    Risk Hedging Program
  over-the-counter
 F-40




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 12 
    Risk Management Activities (Continued)
    Ineffective-


Realized


Estimate of OCI toFair Value


ness


Gain (Loss)


be Reclassed toTerm


December 31,


Year Ended December 31,


Year Ended December 31,


Earnings in theFrom


To


2006


2005


2006


2005


2006


2005


Next 12 Months(In thousands)West Texas Intermediate crude
    oil(1)(2)


Put



September 2005



December 2007


$
178


$
2,927


$
(40
)

$
(35
)

$
(1,376
)

$
(12
)

$
2,703Natural Gas(3)


Put



January 2006



December 2009



14,118



12,808



8







7,553







4,778Natural Gas Liquids(3)


Put



January 2006



December 2008



3,714



18,909



(125
)






(4,919
)






7,355Natural Gas Liquids(3)


Swap



January 2006



December 2008



(5,187
)


(3,600
)


(195
)






448







944Natural Gas Call Spreads(4)


Put/Call



January 2007



December 2011



7,589























1,213West Texas Intermediate crude oil(1)


Put



January 2007



December 2011



4,603























34Natural Gas Liquids(3)


Put



January 2007



December 2011



7,165







(1
)














675     (1)
    
    The derivatives are intended to hedge the risk of weakening NGL
    prices with offsetting increases in the value of the crude oil
    puts based on the correlation between NGL prices and crude oil
    prices.(2)
    
    For the year ended December 31, 2005, we recorded a fair
    value gain in other revenue of $405,000 related to these put
    contracts prior to their designation as cash flow hedges
    effective October 25, 2005.(3)
    
    The derivatives are intended to hedge the risk of extreme
    adverse fluctuations in the prices of the commodities hedged.(4)
    
    The call spread is intended to hedge a portion of our net
    operational short position in natural gas that results when we
    operate in a processing mode at our Houston Central Processing
    Plant against extreme price fluctuations in the underlying price
    indices. The call spread reduces risk to the profitability and
    cash flow of the Houston Central Processing Plant and is
    therefore designated as a cash flow hedge.      Interest
    Rate Risk Hedging Program
   F-41




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 12 
    Risk Management Activities (Continued)
     Net Amounts


Amounts


Fair ValueNotional


Fixed


Received in


Paid in


December 31,Effective Date

Expiration Date


Amount


Rate


2006


2005


2006October 24, 2005


July 31, 2010


$
25,000,000



4.7150
%

$
83,000


$
26,000


$
212,000October 24, 2005


July 31, 2010


$
25,000,000



4.7075
%

$
85,000


$
28,000


$
219,000     Note 13 
    Fair Value of Financial Instruments
    Note 14 
    Commitments and Contingencies
  Commitments
  2007 2008 2009 2010 2011
   F-42




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 14 
    Commitments and Contingencies (Continued)
    Guarantees
  Guarantors Accounting and Disclosure Requirements
    for Guarantees, Including Indirect Guarantees of Indebtedness of
    Others.
    2007


2008


TotalLease residual values

$
55


$
54


$
109       Regulatory
    Compliance
    Litigation
    F-43




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 15 
    Supplemental Disclosures to the Statements of Cash
    Flows
  Cash
    paid during each of the periods presented (in
    thousands)
  Year Ended December 31,2006


2005


2004Interest, net of amounts
    capitalized

$
26,884


$
9,666


$
3,891Taxes

$



$
15


$
   Supplemental
    disclosures of noncash investing and financing activities (in
    thousands)
  Year Ended December 31,2006


2005


2004Decrease in equity in earnings
    from unconsolidated affiliates

$
258


$
120


$
120Decrease in accounts receivable
    from affiliates


(258
)


(120
)


(120
)Decrease (increase) in other assets


24



(24
)


Increase in property, plant and
    equipment


(2,933
)


(3,448
)


(890
)Decrease in accounts payable


2,346



2,899



Decrease other current liabilities


217



1,015



Increase in other noncurrent
    liabilities


516



215



890Decrease (increase) in equity
    offering costs


107



(561
)


Decrease in distributions to
    unitholders


(277
)






Increase in notes payable


2,065



2,129



Increase in prepayments and other
    current assets


(2,065
)


(2,129
)


   Note 16 
    Segment Information
   F-44




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 16 
    Segment Information (Continued)
     Texas


TexasMid-Continent


Gulf Coast


Gulf CoastOperations


Pipelines


Processing


Corporate


Eliminations


TotalYear Ended December 31,
    2006:Sales to external customers

$
411,196


$
225,929


$
221,794


$
1,353


$



$
860,272Intersegment sales






165,822



30,156







(195,978
)


Interest and other financing costs






2







32,902







32,904Depreciation and amortization


23,054



5,981



2,471



487







31,993Equity in earnings in consolidated
    affiliates


(91
)


(1,206
)














(1,297
)Segment profit (loss)


50,749



19,398



36,700



(41,733
)






65,114Segment assets


584,956



146,752



101,521



12,703



(6,874
)


839,058Capital expenditures


27,752



19,881



12,455



2,194







62,282Year Ended December 31,
    2005:Sales to external customers

$
200,426


$
373,007


$
173,950


$
360


$



$
747,743Intersegment sales






202,414



65,411







(267,825
)


Interest and other financing costs






3,468



456



16,923



(386
)


20,461Depreciation and amortization


9,181



5,296



2,435



140







17,052Equity in loss (earnings) in
    consolidated affiliate


7



(934
)














(927
)Segment profit (loss)


23,610



11,553



17,163



(21,974
)






30,352Segment assets


573,795



146,217



74,495



45,808



(47,565
)


792,750Capital expenditures


484,206



5,544



2,094



1,128







492,972Year Ended December 31,
    2004:Sales to external customers

$



$
274,595


$
163,061


$



$



$
437,656Intersegment sales






146,812



18,442







(165,254
)


Interest and other financing costs






2,971



3,134



17,643



(588
)


23,160Depreciation and amortization






4,832



2,390



65







7,287Equity in loss from unconsolidated
    affiliate






(419
)














(419
)Segment profit (loss)






11,878



7,195



(19,988
)






(915
)Capital expenditures






7,989



820



111







8,920   F-45




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 17 
    Quarterly Financial Data (Unaudited)
  Year 2006Quarter EndedMarch 31


June 30


September 30


December 31


Year(In thousands, except per unit information)Revenue

$
213,960


$
209,627


$
231,311


$
205,374


$
860,272Operating income


15,347



26,148



31,090



23,727



96,312Net income


7,413



18,887



22,283



16,531



65,114Basic net income per common unit


0.41



1.04



1.22



0.87



3.54Diluted net income per common unit


0.40



1.03



1.21



0.86



3.49Basic net income per subordinated
    unit


0.41



1.04



1.22



0.87



3.54Diluted net income per
    subordinated unit


0.41



1.03



1.22



0.87



3.53   Year 2005Quarter EndedMarch 31


June 30


September 30(1)


December 31(1)


Year(In thousands, except per unit information)Revenue

$
126,850


$
109,122


$
216,667


$
295,104


$
747,743Operating income


6,381



6,399



13,533



23,860



50,173Net income


5,425



5,516



5,159



14,252



30,352Basic net income per common unit


0.51



0.52



0.34



0.89



2.40Diluted net income per common unit


0.51



0.52



0.34



0.84



2.29Basic net income per subordinated
    unit


0.51



0.52



0.34



0.89



2.40Diluted net income per
    subordinated unit


0.51



0.52



0.34



0.89



2.40Basic net income per Class B
    unit










0.39



0.39



1.33Diluted net income per
    Class B unit










0.38



0.39



0.77     (1)
    
    Our historical results of operations for the quarters ended
    September 30, 2005 and December 31, 2005 may not be
    comparable to earlier 2005 quarters or quarters in 2006 as a
    result of the ScissorTail Acquisition on August 1, 2005.  F-46




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM            Deloitte &
    Touche LLP
     F-47




---



##### Table of Contents



WEBB/DUVAL
    GATHERERS
  UNAUDITED
    BALANCE SHEETS  December 31,2006


2005ASSETSCurrent assets:Cash and cash equivalents

$
2,959,644


$
961,297Accounts receivable


1,608,239



1,650,258Accounts receivable from affiliates


15,765



748,847Prepayments and other current
    assets


11,306



17,600Total current assets


4,594,954



3,378,002Property and equipment, net


8,104,208



8,031,894Total assets

$
12,699,162


$
11,409,896LIABILITIES AND PARTNERS
    CAPITALCurrent liabilities:Accounts payable

$
1,653,594


$
1,704,462Accounts payable to affiliates


833,133



996,303Accrued liabilities


15,395



Total current liabilities


2,502,122



2,700,765Noncurrent liabilities


47,501



44,386Commitments and contingencies
    (Note 9)Total partners capital


10,149,539



8,664,745Total liabilities and
    partners capital

$
12,699,162


$
11,409,896    F-48




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  STATEMENTS
    OF OPERATIONS  Year Ended December 31,2006


2005


2004(Unaudited)


(Unaudited)Revenue:Natural gas sales

$
730,757


$
105,851


$
330,919Natural gas sales to affiliates


2,551,005



3,953,330



2,144,428Transportation and gathering fees


961,463



1,014,645



1,018,399Transportation and gathering fees
    from affiliates


464,796



628,775



640,812Condensate sales


1,229,312



1,033,180



421,169Other


23,500



6,400



26,264Other  affiliates






67,033



23,000Total revenue


5,960,833



6,809,214



4,604,991Costs and expenses:Cost of natural gas sold


921,276



2,963,843



575,735Cost of natural gas 
    affiliates


1,514,566



544,074



1,642,916Operations and maintenance


921,666



924,723



853,057Depreciation and amortization


743,050



701,552



654,929General and administrative


298,205



284,227



315,536Taxes other than income


114,330



120,170



116,518Total cost and expenses


4,513,093



5,538,589



4,158,691Operating Income


1,447,740



1,270,625



446,300Interest income


37,054







Net income

$
1,484,794


$
1,270,625


$
446,300    F-49




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  STATEMENTS
    OF CASH FLOWS  Year Ended December 31,2006


2005


2004(Unaudited)


(Unaudited)Cash Flows From Operating
    Activities:Net income

$
1,484,794


$
1,270,625


$
446,300Adjustments to reconcile net
    income to net cash provided by operating activities:Depreciation and amortization


743,050



701,552



654,929Other noncash items


3,115



10,544



(Increase) decrease in:Accounts receivable


42,019



524,120



476,781Accounts receivable from affiliates


733,082



(706,685
)


41,704Prepayments and other current
    assets


6,294



(406
)


1,619Increase (decrease) in:Accounts payable


(50,868
)


364,268



(1,692,547
)Accounts payable to affiliates


(163,170
)


(900,947
)


312,342Other current liabilities


15,395







(35,380
)Net cash provided by operating
    activities


2,813,711



1,263,071



205,748Cash Flows From Investing
    Activities:Additions to property and equipment


(1,716,531
)


(416,269
)


(412,466
)Proceeds from sale of assets
    (Note 6)


901,167







Net cash used in investing
    activities


(815,364
)


(416,269
)


(412,466
)Cash Flows From Financing
    Activities:










Net increase (decrease) in cash
    and cash equivalents


1,998,347



846,802



(206,718
)Cash and cash equivalents,
    beginning of year


961,297



114,495



321,213Cash and cash equivalents, end of
    year

$
2,959,644


$
961,297


$
114,495    F-50




---



##### Table of Contents



WEBB/DUVAL
    GATHERERS
  STATEMENTS
    OF PARTNERS CAPITAL  Balance, December 31, 2003
    (unaudited)

$
6,947,820Net income


446,300Balance, December 31, 2004


7,394,120Net income (unaudited)


1,270,625Balance, December 31, 2005
    (unaudited)


8,664,745Net income (unaudited)


1,484,794Balance, December 31, 2006
    (unaudited)

$
10,149,539    F-51




---



##### Table of Contents



WEBB/DUVAL
    GATHERERS



NOTES TO
    FINANCIAL STATEMENTS  Note 1 
    Organization and Basis of Presentation
      Note 2 
    Summary of Significant Accounting Policies
  Use of
    Estimates
    Cash
    and Cash Equivalents
    Concentration
    and Credit Risk
      Allowance
    for Doubtful Accounts
   F-52




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
    Property
    and Equipment
  15-year 20-year
    and/or Accounting for Conditional Asset Retirement
    Obligations, an interpretation of FASB Statement
    No. 143, and/or Accounting for Asset Retirement
    Obligations,
  Transportation
    and Exchange Imbalances
  mark-to-market
 F-53




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary of Significant Accounting Policies (Continued)
   Revenue
    Recognition
  agreed-upon
    Derivatives
  Accounting for
    Derivative Instruments and Hedging Activities,
  Income
    Taxes
    Accounting
    for Uncertainty in Income Taxes  An Interpretation of
    FASB Statement No. 109. Accounting for Income
    Taxes
  Note 3 
    New Accounting Pronouncements
  Accounting
    Changes and Error Corrections
  Accounting Changes and Error Corrections.
 F-54




---



##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 3 
    New Accounting Pronouncements (Continued)
   Accounting
    for Purchases and Sales of Inventory with the Same
    Counterparty
  No. 04-13, Accounting for Purchases and Sales of Inventory with
    the Same Counterparty 04-13). 04-13, 04-13
  Accounting
    for Servicing of Financial Assets
  Accounting for Servicing of Financial
    Assets  an amendment of FASB Statement
    No. 140, available-for-sale
  Fair
    Value Measurements
  Fair Value Measurements.
  Defined
    Benefit Pension and Other Postretirement Plans
  Employers Accounting for Defined Benefit Pension and
    Other Postretirement Plans  an amendment of FASB
    Statements No. 87, 88, 106, and 132(R).
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
 F-55




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 3 
    New Accounting Pronouncements (Continued)
    Quantifying
    Misstatements
  Considering the Effects of Prior Year Misstatements
    When Quantifying Misstatements in Current Year Financial
    Statements,
  Note 4 
    Property and Equipment and Asset Retirement
    Obligations
    December 31,2006


2005(Unaudited)Property and equipment, at cost:Pipelines and equipment

$
26,446,554


$
25,461,503Construction in progress


22,620



192,30726,469,174



25,653,810Less accumulated depreciation and
    amortization


(18,364,966
)


(17,621,916
)Total property and equipment, net

$
8,104,208


$
8,031,894   Asset retirement obligations. (i) rights-of-way
    Asset retirement obligation
    liability balance, December 31, 2004

$
Adoption of FIN 47 for
    conditional obligations (unaudited)


44,386Asset retirement obligation
    liability balance, December 31, 2005 (unaudited)


44,386Accretion of FIN 47 for
    conditional obligations (unaudited)


3,115Asset retirement obligation
    liability balance, December 31, 2006 (unaudited)

$
47,501    F-56




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 5 
    Risk Management Activities
    Note 6 
    Related Party Transactions
  Operations
    Services
      Natural
    Gas Transportation and Related Transactions
  CFS/AD
   F-57




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 6 
    Related Party Transactions (Continued)
          Note 7 
    Business Segment and Customer Information
     F-58




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##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 8 
    Fair Value of Financial Instruments
    Note 9 
    Commitments and Contingencies
  Commitments
      Guarantees
  Guarantors Accounting and Disclosure Requirements
    for Guarantees, Including Indirect Guarantees of Indebtedness of
    Others.
    2007


2008


TotalLease residual values

$
40,514


$
15,722


$
56,236     Regulatory
    Compliance
    Litigation
   F-59




---



##### Table of Contents



WEBB/DUVAL
    GATHERERS
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 9 
    Commitments and Contingencies (Continued)
    Note 10 
    Supplemental Disclosures to the Statements of Cash
    Flows
  Supplemental
    disclosures of noncash investing and financing
    activities
  Year Ended December 31,2006


2005


2004(Unaudited)


(Unaudited)Increase in property, plant and
    equipment

$



$
33,842


$
Increase in other noncurrent
    liabilities






44,386



  F-60




---



##### Table of Contents



Index to
    Exhibits
    Number

Description3
.1

Certificate of Formation of Copano
    Energy Holdings, L.L.C. (now Copano Energy, L.L.C.)
    (incorporated by reference to Exhibit 3.1 to Registration
    Statement on
    Form S-1
    filed July 30, 2004).3
.2

Certificate of Amendment to
    Certificate of Formation of Copano Energy Holdings, L.L.C. (now
    Copano Energy, L.L.C.) (incorporated by reference to
    Exhibit 3.2 to Registration Statement on
    Form S-1
    filed July 30, 2004).3
.3

Second Amended and Restated
    Limited Liability Company Agreement of Copano Energy, L.L.C.
    (incorporated by reference to Exhibit 3.3 to Post-Effective
    Amendment No. 1 to Registration Statement on
    Form S-1/A
    filed December 15, 2004).3
.4

Amendment No. 1 to Second
    Amended and Restated Limited Liability Company Agreement of
    Copano Energy, L.L.C. (incorporated by reference to
    Exhibit 3.4 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).3
.5

Amendment No. 2 to Second
    Amended and Restated Limited Liability Company Agreement of
    Copano Energy, L.L.C. (incorporated by reference to
    Exhibit 3.5 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).4
.1

Indenture dated as of
    February 7, 2006, among Copano Energy, L.L.C., Copano
    Energy Finance Corporation, the Guarantors parties thereto and
    U.S. Bank National Association, as trustee (incorporated by
    reference to Exhibit 4.1 to Current Report on
    Form 8-K
    filed February 8, 2006).4
.2

Rule 144A Global Note
    representing $224,500,000 principal amount of 8.125% Senior
    Notes due 2016 (incorporated by reference to Exhibit 4.2 to
    Current Report on
    Form 8-K
    filed February 8, 2006).4
.3

Regulation S Global Note
    representing $500,000 principal amount of 8.125% Senior Notes
    due 2016 (incorporated by reference to Exhibit 4.3 to
    Current Report on
    Form 8-K
    filed February 8, 2006).4
.4

Registration Rights Agreement
    dated as of February 7, 2006, among Copano Energy, L.L.C.,
    Copano Energy Finance Corporation, the Guarantors parties
    thereto and the Initial Purchasers named therein (incorporated
    by reference to Exhibit 4.4 to Current Report on
    Form 8-K
    filed February 8, 2006).4
.5

Class B Unit and Common Unit
    Purchase Agreement dated as of June 17, 2005 by and among
    Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company,
    RCH Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise
    Energy Infrastructure Corporation, Tortoise Energy Capital
    Corporation, Goldman, Sachs & Co., Energy Income and
    Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Alerian
    Opportunity Partners LP, Alerian Capital Partners LP, Strome
    HedgeCap, LP, Strome Alpha, LP and Strome Family Foundation
    (incorporated by reference to Exhibit 10.27 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).4
.6

Registration Rights Agreement made
    and entered into as of August 1, 2005, by and among Copano
    Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH
    Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise
    Energy Infrastructure Corporation, Tortoise Energy Capital
    Corporation, Goldman, Sachs & Co., Energy Income and
    Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Alerian
    Opportunity Partners LP, Alerian Capital Partners LP, Strome MLP
    Fund, L.P., Strome Alpha, LP and Strome Family Foundation
    (incorporated by reference to Exhibit 10.28 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).4
.7

Common Unit Purchase Agreement
    dated as of December 29, 2005, by and among Copano Energy,
    L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and
    Royal Bank of Canada (incorporated by reference to
    Exhibit 4.7 to Annual Report on
    Form 10-K
    filed March 16, 2006).4
.8

Registration Rights Agreement
    dated as of December 29, 2005, by and among Copano Energy,
    L.L.C. and ZLP Fund, L.P., Structured Finance Americas, LLC and
    Royal Bank of Canada (incorporated by reference to
    Exhibit 4.7 to Annual Report on
    Form 10-K
    filed March 16, 2006).10
.1

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).




---



##### Table of Contents



Number

Description10
.2

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
.3

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
.4

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
.5

Assignment and Assumption
    Agreement between Copano/Operations, Inc. and CPNO Services,
    L.P. effective January 1, 2005 with respect to Employment
    Agreement between Copano/Operations, Inc., R. Bruce
    Northcutt and the Copano Controlling Entities, as amended
    (incorporated by reference to Exhibit 10.10 to Annual
    Report on
    Form 10-K
    filed March 31, 2005).10
.6

Second Amendment to Employment
    Agreement between CPNO Services, L.P., R. Bruce Northcutt and
    the Copano Controlling Entities, effective March 1, 2005
    (incorporated by reference to Exhibit 10.10 to Annual
    Report on
    Form 10-K
    filed March 31, 2005).10
.7

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
.8

Assignment and Assumption
    Agreement between Copano/Operations, Inc. and CPNO Services,
    L.P. effective January 1, 2005 with respect to Employment
    Agreement between Copano/Operations, Inc. and James J.
    Gibson, III (incorporated by reference to
    Exhibit 10.10 to Annual Report on
    Form 10-K
    filed March 31, 2005).10
.9

First Amendment to Employment
    Agreement between CPNO Services, L.P. and James J.
    Gibson, III, effective March 1, 2005 (incorporated by
    reference to Exhibit 10.10 to Annual Report on
    Form 10-K
    filed March 31, 2005).10
.10

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
.11

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
.12

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
.13

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
.14

Form of Grant of Options
    (incorporated by reference to Exhibit 10.17 to Quarterly
    Report on
    Form 10-Q
    filed December 21, 2004).10
.15

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
.16

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
.17

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
.18

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).




---



##### Table of Contents



Number

Description10
.19

2005 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed March 2, 2005).10
.20

Unitholder Voting Agreement dated
    as of August 1, 2005 by and among Copano Partners Trust,
    MBP III AIV, L.P., MBP Onapoc Holdings LLC, R. Bruce
    Northcutt and Matthew J. Assiff (incorporated by reference to
    Exhibit 10.29 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.21

Credit Agreement dated as of
    August 1, 2005 among Copano Energy, L.L.C., as the
    Borrower, Bank of America, N.A., as Administrative Agent and L/C
    Issuer, Comerica Bank and U.S. Bank National Association,
    as Co-Syndication Agents, Bank of Scotland and Fortis Capital
    Corp., as Co-Documentation Agents and The Other Lenders Party
    Hereto and Banc of America Securities LLC, as Sole Lead Arranger
    and Sole Book Manager (incorporated by reference to
    Exhibit 10.30 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.22

Bridge Loan Agreement dated as of
    August 1, 2005 among Copano Energy, L.L.C., as the
    Borrower, Banc of America Bridge LLC, as Administrative Agent
    and The Other Lenders Party Hereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Book Manager
    (incorporated by reference to Exhibit 10.31 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).10
.23

Employment Agreement between CPNO
    Services, L.P. and John A. Raber dated as of August 1, 2005
    (incorporated by reference to Exhibit 10.32 to Quarterly
    Report on
    Form 10-Q
    filed August 15, 2005).10
.24

Employment Agreement between
    ScissorTail Energy, L.L.C. and Bruce Roderick dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.33 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.25

Employment Agreement between
    ScissorTail Energy, L.L.C. and Sharon Robinson dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.34 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.26

Employment Agreement between
    ScissorTail Energy, L.L.C. and Thomas Coleman dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.35 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.27

Employment Agreement between
    ScissorTail Energy, L.L.C. and Lee E. Fiegener dated as of
    August 1, 2005 (incorporated by reference to
    Exhibit 10.36 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.28

Form of Unit Option Grant under
    the Copano Energy, L.L.C. Long-Term Incentive Plan (ScissorTail
    Energy, LLC Officers) (incorporated by reference to
    Exhibit 10.37 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.29

Form of Restricted Unit Grant
    under the Copano Energy, L.L.C. Long-Term Incentive Plan
    (ScissorTail Energy, LLC Officers) (incorporated by reference to
    Exhibit 10.38 to Quarterly Report on
    Form 10-Q
    filed August 15, 2005).10
.30

Form of Indemnification Agreement
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed November 2, 2005).10
.31

First Amendment to Copano Energy,
    L.L.C. Long-Term Incentive Plan dated October 27, 2005
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed November 2, 2005).10
.32

Purchase Agreement dated as of
    January 31, 2006, among Copano Energy, L.L.C., Copano
    Energy Finance Corporation, the Guarantors parties thereto and
    the Initial Purchasers named therein (incorporated by reference
    to Exhibit 10.1 to Current Report on
    Form 8-K
    filed February 8, 2006).10
.33

2006 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed February 21, 2006).10
.34

Amended and Restated Gas
    Processing Contract entered into as of February 1, 2006,
    between Kinder Morgan Texas Pipeline, L.P. and Copano
    Processing, L.P. (incorporated by reference to Exhibit 10.1
    to Quarterly Report on
    Form 10-Q
    filed May 10, 2006).10
.35

First Amendment to Credit
    Agreement dated as of January 26, 2006 among Copano Energy,
    L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and the other Lenders party thereto
    (incorporated by reference to Exhibit 10.2 to Quarterly
    Report on
    Form 10-Q
    filed May 10, 2006).10
.36

Form of Grant of Restricted Units
    (Directors) (incorporated by reference to Exhibit 10.3 to
    Current Report on
    Form 8-K
    filed May 30, 2006).




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##### Table of Contents



Number

Description10
.37

Form of Grant of Options
    (Employees) (incorporated by reference to Exhibit 10.2 to
    Current Report on
    Form 8-K
    filed May 30, 2006).10
.38

Form of Grant of Restricted Units
    (Employees) (incorporated by reference to Exhibit 10.4 to
    Current Report on
    Form 8-K
    filed May 30, 2006).10
.39

Second Amendment to Copano Energy,
    L.L.C. Long-Term Incentive Plan dated May 25, 2006
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed May 30, 2006).10
.40

Loan Agreement dated as of
    September 29, 2006, among Copano Energy, L.L.C., as the
    Borrower, Banc of America Bridge LLC, as Administrative Agent,
    and The Other Lenders Party Hereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Lead Manager
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed October 5, 2006).10
.41

Second Amendment to Credit
    Agreement dated as of September 20, 2006 among Copano
    Energy, L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and the other Lenders party thereto
    (incorporated by reference to Exhibit 10.1 to Quarterly
    Report on
    Form 10-Q
    filed November 9, 2006).10
.42

Form of Grant of Restricted Units
    (Directors) (incorporated by reference to Exhibit 10.1 to
    Current Report on
    Form 8-K
    filed November 20, 2006).10
.43

Independent Director Compensation
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed November 20, 2006).10
.44

Amended and Restated Loan
    Agreement dated as of January 12, 2007, among Copano
    Energy, L.L.C., as the Borrower, Bank of America, N.A., as
    Administrative Agent and L/C Issuer, JPMorgan Chase Bank, N.A.
    and Wachovia Bank, National Association, as Co-Syndication
    Agents and The Other Lenders Party thereto and Banc of America
    Securities LLC, as Sole Lead Arranger and Sole Book Manager
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed January 19, 2007).10
.45

2007 Administrative Guidelines for
    the Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed February 20, 2007).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.     *
    
    Filed herewith.
    
    Portions of this exhibit have been omitted pursuant to a request
    for confidential treatment.