##### 





UNITED STATES SECURITIES AND
    EXCHANGE COMMISSIONWashington, 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, 2007ORo

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(State of
    organization)

51-0411678(I.R.S. Employer
    Identification No.)2727 Allen Parkway, Suite 1200
    Houston, Texas(Address of principal
    executive offices)

77019(Zip
    Code)   (713) 621-9547
  (Registrants telephone
    number, including area code)
  None
 (Former name, 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 þ

Accelerated
    filer o

Non-accelerated
    filer o
    (Do not check if a smaller reporting company)

Smaller reporting
    company 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 15, 2008

Part III




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##### 





TABLE OF
    CONTENTS
  PagePART IItem 1.


Business


1Item 1A.


Risk Factors


26Item 1B.


Unresolved Staff Comments


41Item 2.


Properties


41Item 3.


Legal Proceedings


42Item 4.


Submission of Matters to a Vote of Security Holders


42PART IIItem 5.


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


43Item 6.


Selected Financial Data


47Item 7.


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


51Item 7A.


Quantitative and Qualitative Disclosures about Market Risk


72Item 8.


Financial Statements and Supplementary Data


78Item 9.


Changes in and Disagreements with Accountants on Accounting and
    Financial Disclosure


78Item 9A.


Controls and Procedures


78Item 9B.


Other Information


82PART IIIItem 10.


Directors and Executive Officers of the Registrant


83Item 11.


Executive Compensation


83Item 12.


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


83Item 13.


Certain Relationships and Related Parties


83Item 14.


Principal Accountant Fees and Services


83PART IVItem 15.


Exhibits and Financial Statement Schedules


84FINANCIAL STATEMENTSCopano Energy, L.L.C. Index to Financial Statements


F-1  i




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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.
    /d:

Per day$/gal:

U.S. dollars per gallonBbls:

BarrelsBcf:

One billion cubic feetBtu:

British thermal unitsMMBtu:

One million British thermal unitsMcf:

One thousand cubic feetNGLs:

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 processedTcf:

One trillion cubic feetthroughput:

The volume of product transported or passing through a
    pipeline, plant, terminal or other facility   Item 1.
    Business  The following discussion of our business segments provides
    information regarding our principal natural gas processing
    plants, pipelines and other assets. For a discussion of our
    results of operations, including throughput and processing
    rates, please read Item 7 of this report, captioned
    Managements Discussion and Analysis of Financial
    Condition and Results of Operation.
  General
  67-mile
    Recent
    Developments
  Declaration of Distribution.
  Hedge Activity.
 1




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##### 



Public Offering of
    81/8% Senior
    Notes due 2016 and Reduction of Credit Facility
    Debt. 1 8
  Cantera Acquisition. 106-mile, 62-mile
  Amended and Restated Revolving Credit
    Facility.
  Cimmarron Acquisition.
 2




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##### 



Business
    Strategy
    
    Pursuing growth from our existing assets.  In
    many cases, 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 of capacity.
    Pursuing complementary acquisitions and organic expansion
    opportunities.  We seek to use our acquisition and
    integration experience to continue to make complementary
    acquisitions of midstream assets in our operating areas that
    provide opportunities to expand either the acquired assets or
    our existing assets to increase utilization of capacity. 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. Generally, we pursue
    arrangements under which the fee for our services is sufficient
    to provide us with positive operating margins irrespective of
    commodity prices. For example, we pursue processing arrangements
    at our Houston Central plant providing that we may elect to
    condition natural gas for a fee when processing is economically
    unattractive.    
    Exploiting the operating flexibility of our
    assets.  We can modify the operation of our assets
    to maximize our cash flows. For example, our Houston Central
    plant has the ability to transition rapidly between processing
    and conditioning of natural gas, which provides us with
    significant benefits during periods when processing natural gas
    is not profitable. Also, our Houston Central and Paden plants
    each have ethane-rejection capability (the ability to reduce the
    ethane extracted from natural gas in processing), which we
    employ as market conditions warrant.
    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. For example, with the Cantera acquisition in
    October 2007, we expanded into the Rocky Mountains region, and
    with the acquisition of ScissorTail Energy in August 2005, we
    expanded our operations to pursue opportunities in Oklahoma.  Our
    Operations
   3




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##### 



Our
    Operating Segments
  Overview
    Copano
    Energy Operating Segments
  Year EndedDecember 31, 2007Pipeline
    Miles(1)





Average/Number of


Throughput/


Throughput/


UtilizationProcessing


Inlet


Inlet


ofSegment

Primary Assets

Plants


Capacity(2)(3)


Volumes(2)(3)


CapacityOklahoma

Natural Gas Pipelines


3,680



234,100



166,207



71
%Processing
    Plants(4)(5)


4



158,000



81,134



51
%Crude Oil Pipelines


69



3,960



3,600



91
%Texas

Natural Gas
    Pipelines(6)


1,853



945,300



365,939



38
%Processing
    Plants(7)


2



900,000



544,016



60
%NGL
    Pipelines(8)


150



30,900



17,090



55
%Rocky Mountains

Natural Gas
    Pipelines(9)


463



1,140,000



821,434



72
%     (1)
    
    Natural gas pipeline miles for Oklahoma and Texas exclude
    2,996 miles and 576 miles, respectively, of inactive
    pipelines that are being held for potential future development.(2)
    
    Many pipeline 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)
    
    Natural gas pipeline throughputs and inlet capacity are measured
    in Mcf/d. Crude oil and NGL pipeline throughputs are measured in
    Bbls/d.(4)
    
    Includes the Southern Dome plant owned by Southern Dome, LLC, or
    Southern Dome, an unconsolidated limited liability company in
    which we own a majority interest. The plant is designed for
    operating capacity of 30,000 Mcf/d but is currently
    configured for 18,000 Mcf/d.(5)
    
    In addition to transporting natural gas to our plants for
    processing, our Oklahoma segment delivers natural gas to
    six third-party plants in exchange for a portion of the
    product revenues. Average daily throughput volumes processed at
    third-party plants for our Oklahoma segment were
    41,382 Mcf/d for the year ended December 31, 2007.(6)
    
    Includes the
    144-mile
    Webb/Duval system owned by Webb/Duval Gatherers, or Webb Duval,
    an unconsolidated partnership in which we hold a 62.5% interest.(7)
    
    In addition to our Houston Central plant, our Texas segment
    includes a processing plant in Lake Charles, Louisiana, which we
    acquired as part of the Cantera acquisition. This plant, which
    has had no material operations since the acquisition, is managed
    by the personnel who manage our Texas operations.(8)
    
    Includes our
    46-mile
    Brenham NGL pipeline, which we lease from Kinder Morgan Texas
    Pipeline and expect to place into service in March 2008.(9)
    
    Owned by Bighorn and Fort Union, in which we own 51.0% and
    37.04% interests, respectively.  Oklahoma
    
    ten primarily low-pressure gathering systems occupying
    approximately 53,000 square miles;
    a crude oil pipeline; and
    four processing plants, one of which we own through our majority
    interest in Southern Dome. 4




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##### 



5




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##### 



Oklahoma
    Pipelines
  Diameter of





Year Ended December 31,2007Length


Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


of CapacityNatural Gas Pipelines:Stroud


778



22-
    162



102,000



90,743



89
%Osage


549



22- 82



26,000



18,883



73
%Milfay


351



22-
    162



15,000



13,389



89
%Glenpool


1,015



22-
    102



23,000



9,704



42
%Twin Rivers


537



22-
    122



16,000



11,182



70
%Mountain(3)


164



22-
    202



42,000



18,971



45
%Central
    Oklahoma(4)


190



22-
    122



4,100



3,132



76
%Tomahawk(5)


96



32-
    102



6,000



204



3
%Oklahoma Natural Gas Gathering


3,680







234,100



166,207Crude Oil
    Pipeline(6)


69



42-
    62



3,960



3,600



91
%     (1)
    
    Many capacity values are based on current operating
    configurations and could be increased through additional
    compression, increased delivery meter capacity or other facility
    upgrades.(2)
    
    Natural gas pipeline throughputs are measured in Mcf/d. Crude
    oil throughputs are measured in Bbls/d.(3)
    
    The Mountain system consists of three systems: Blue Mountain,
    Cyclone Mountain and Pine Mountain.(4)
    
    Excludes 2,996 miles of inactive pipelines held for
    potential future development. Data reported for our Central
    Oklahoma system is only for the period from May 1, 2007
    (the date of our Cimmarron acquisition) through
    December 31, 2007.(5)
    
    The Tomahawk system was activated in April 2007 and is expected
    to be operational in March 2008.(6)
    
    Data reported for our crude oil pipeline is only for the period
    from May 1, 2007 (the date of our Cimmarron acquisition)
    through December 31, 2007.  Oklahoma
    Processing
  Year Ended December 31, 2007Average


Utilization


Average ProcessingAssociated



Throughput


Inlet


of


VolumesProcessing Plants

Gathering System

Facilities

Capacity(1)


Volumes(1)


Capacity


NGLs


ResiduePaden

Stroud

Cryogenic/refrigeration


100,000



54,347



54
%


8,044



42,042Tomahawk

Ethane rejectionNitrogen rejection(3)Milfay

Milfay

Propane refrigeration


15,000



12,428



83
%


796



10,632Glenpool

Glenpool

Cryogenic


25,000



9,266



37
%


508



9,314Southern
    Dome(2)

Southern Dome

Propane refrigeration


18,000



5,093



28
%


244



4,706Oklahoma Processing






158,000



81,134



52
%


9,592



66,694     (1)
    
    Throughput capacity and inlet volumes are measured in Mcf/d. NGL
    volumes are measured in Bbls/d. Residue volumes are measured in
    MMBtu/d.(2)
    
    We hold a majority interest in Southern Dome, which owns the
    Southern Dome plant. The plant is designed for operating
    capacity of 30,000 Mcf/d but is currently configured for
    18,000 Mcf/d. 6




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##### 



(3)
    
    Nitrogen rejection capability at our Paden plant is expected to
    become operational in March 2008 and will be limited to
    60,000 Mcf/d.    Stroud
    System and Paden Processing Plant
          Osage
    System
    Milfay
    System and Processing Plant
    Glenpool
    System and Processing Plant
    Twin
    Rivers System
   7




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##### 



Mountain
    Systems
    Central
    Oklahoma System
    Tomahawk
    System
    Crude Oil
    Pipeline
    Southern
    Dome
      Texas
   8




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9




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##### 



Texas
    Pipelines
  Year EndedDecember 31, 2007Length


Diameter of Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


of CapacityNatural Gas Pipelines:South
    Texas(3)(4)


1,102



22-
    202



538,800



187,140



35
%Houston Central


313



22-
    122



239,000



123,224



52
%Upper Gulf Coast


230



22-
    202



139,000



36,728



26
%North
    Texas(5)


208



32-
    122



28,500



18,847



66
%NGL Pipelines:Sheridan NGL
    Pipeline(6)


104



62



30,900



17,090



55
%Brenham NGL
    Pipeline(7)


46



62











     (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.(2)
    
    Natural gas pipeline throughputs are measured in Mcf/d. NGL
    throughputs are measured in Bbls/d.(3)
    
    Includes our Webb/Duval system 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
    intercompany transactions.(5)
    
    Excludes 576 miles of inactive pipelines held for potential
    future development. Data reported for our North Texas System is
    only for the period from May 1, 2007 (the date of our
    Cimmerron acquisition) through December 31, 2007.(6)
    
    We use the eastern portion of our Sheridan NGL pipeline to
    transport butylene and the western portion to transport NGLs
    from our Houston Central plant to Enterprise Products
    Partners Seminole pipeline. The central portion of our
    Sheridan NGL pipeline currently is inactive.(7)
    
    We expect to place the Brenham NGL pipeline into service in
    March 2008.  Texas
    Processing
  Year Ended December 31, 2007Average





Average ProcessingAssociated



Throughput


Inlet


Utilization


Volumes(1)(2)Processing Plants

Gathering System

Facilities

Capacity(1)


Volumes(1)


of Capacity


NGLs


ResidueHouston Central

Central Gulf Coast

Cryogenic/lean oil


700,000



522,051



75
%


16,295



483,933South Texas

Ethane rejectionLake
    Charles(3)



Cryogenic


200,000



11,697
(4)


6
%


260
(4)


11,439
(4)     (1)
    
    Throughput capacity and inlet volumes are measured in Mcf/d. NGL
    volumes are measured in Bbls/d. Residue volumes are measured in
    MMBtu/d.(2)
    
    Production from the Houston Central plant includes average daily
    volumes of 14,444 Bbls/d of ethane, propane, butane and
    natural gasoline mix delivered to the Sheridan NGL pipeline and
    1,756 Bbls/d of stabilized condensate delivered to the
    TEPPCO crude oil pipeline.(3)
    
    The Lake Charles plant, which has had no material operations
    since the acquisition, is managed by personnel who manage our
    Texas segment.(4)
    
    Average inlet volumes and average processing volumes for the
    Lake Charles plant represent two days of activity in October
    2007. 10




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##### 



South
    Texas Systems
  Laredo-to-Katy
        Houston
    Central Systems and Processing Plant
  Laredo-to-Katy
    
    8,029 horsepower of inlet compression, 1,340 of which we
    installed in 2007;
    8,400 horsepower of tailgate compression;
    a 1,200
    gallon-per-minute
    amine treating system for removal of carbon dioxide and
    low-level hydrogen sulfide;
    two 250,000 Mcf/d refrigerated lean oil trains;
    one 200,000 Mcf/d cryogenic turbo-expander train;
    a 25,000 Bbls/d NGL fractionation facility; and
    882,000 gallons of storage capacity for propane, butane-natural
    gasoline mix and stabilized condensate.   11




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##### 




    minimize the level of NGLs we remove from the natural gas stream
    while still meeting downstream pipeline hydrocarbon dew point
    specifications; and
    operate the plant more efficiently, with a substantial reduction
    in the amount of natural gas consumed as fuel.  Laredo-to-Katy
  163-acre
  Sheridan and Brenham NGL Pipelines.
  5-year
  Our Commercial Relationship With Kinder Morgan Texas
    Pipeline. 30-inch-diameter Laredo-to-Katy
  Upper
    Gulf Coast Systems
   12




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##### 



North
    Texas Systems
    Rocky
    Mountains
     13




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Bighorn
    Gathering System
   14




---



##### 



Fort Union
    Gathering System
  106-mile,
  106-mile,
  demand capacity variable
    capacity
   15




---



##### 



Producer
    Services
    Natural
    Gas Supply
      Oklahoma
      Texas
   16




---



##### 



Rocky
    Mountains
      3.8 million-acre
  Competition
        Oklahoma
      Texas
     17




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##### 



Rocky
    Mountains
    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.
    Compression.  Gathering systems are operated at
    pressures that will maximize the total throughput from all
    connected wells. Because wells produce at progressively lower
    field pressures as they age, it becomes increasingly difficult
    to deliver the remaining production in the ground against the
    higher pressure that exists in the connected gathering system.
    Natural gas compression is a mechanical process in which a
    volume of gas at an existing pressure is compressed to a desired
    higher pressure, allowing gas that no longer naturally flows
    into a higher-pressure downstream pipeline to be brought to
    market. Field compression is typically used to allow a gathering
    system to operate at a lower pressure or provide sufficient
    discharge pressure to 18




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##### 



deliver gas into a higher-pressure downstream pipeline. If field
    compression is not installed, then the remaining natural gas in
    the ground will not be produced because it will be unable to
    overcome the higher gathering system pressure. In contrast, if
    field compression is installed, a declining well can continue
    delivering natural gas.  
    Natural gas dehydration.  Natural gas is
    sometimes saturated with water, which must be removed because it
    can form ice and plug different parts of pipeline gathering and
    transportation systems 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, causing a
    greater pressure drop downstream. Dehydration of natural gas
    helps to avoid these potential issues and to meet downstream
    pipeline and end-user gas quality standards.
    Natural gas treating and blending.  Natural gas
    composition varies 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,
    which 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. Natural
    gas can also contain nitrogen, which lowers the heating value of
    natural gas and must be removed to meet pipeline specifications.
    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 these 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.  Natural gas processing
    involves the separation of natural gas into pipeline quality
    natural gas and a mixed NGL stream. The principal component of
    natural gas is methane, but most natural gas also contains
    varying amounts of heavier hydrocarbon components, or NGLs.
    Natural gas is described as lean or rich depending on its
    content of NGLs. Most natural gas produced by a well is not
    suitable for long-haul pipeline transportation or commercial use
    because it contains NGLs and impurities. Natural gas processing
    not only removes unwanted NGLs that would interfere with
    pipeline transportation or use of the natural gas, but also
    extracts hydrocarbon liquids that can have higher value as NGLs.
    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 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 involves removing only an absolute minimum amount
    of NGLs (typically the components of pentane and heavier
    products) from the gas stream. Conditioning involves
    significantly higher temperatures than cryogenic processing and
    consumes less fuel. Conditioning capability is beneficial 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. 19




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##### 



Stabilized condensate is primarily used as a refinery feedstock
    for the production of motor gasoline and other products.    
    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
  FERC Regulation of Intrastate Natural Gas
    Pipelines.
  
    the certification and construction of new facilities;
    the review and approval of cost-based transportation rates;
    the extension or abandonment of services and facilities;
    the maintenance of accounts and records;
    the acquisition and disposition of facilities; and
    the initiation and discontinuation of services.   20




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##### 



and/or
      FERC Regulation of NGL Pipelines.
  FERC Regulation of Crude Oil Pipelines.
  Intrastate Natural Gas Pipeline Regulation.
    Natural Gas Gathering
    Regulation.
 21




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##### 



State Utility Regulation.
  Sales of Natural Gas, Crude Oil and NGLs.
    Environmental,
    Health and Safety Matters
    
    restricting the way we can handle or dispose of wastes;
    limiting or prohibiting construction and operating activities in
    environmentally 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.     22




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##### 



Hazardous Waste.
  Site Remediation.
    Air Emissions.
 23




---



##### 



Water Discharges.
  Pipeline Safety.
    Employee Health and Safety.
 24




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##### 



Anti-terrorism.
  Other Laws and Regulations. and/or
  Office
    Facilities
    Employees
  Page F-1
  Available
    Information
   25




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##### 



1-800-SEC-0330. (http://www.sec.gov)
  (http://www.copanoenergy.com) (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 known 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 our
    minimum quarterly distribution following establishment of cash
    reserves and payment of fees and expenses.
    
    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); 26




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##### 




    our ability to make working capital borrowings under a credit
    facility that are eligible to be used 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.
    Our
    acquisitions potentially involve numerous risks,
    including:
  
    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;
    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
    acquisitions could expose us to potential significant
    liabilities.
   27




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##### 



We may
    not be able to fully execute our business strategy if we
    encounter illiquid capital markets.
      Our
    substantial indebtedness could limit our operating flexibility
    and impair our ability to fulfill our debt
    obligations.
    
    total indebtedness of $630.0 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 $270.0 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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##### 



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.    Because
    of the natural decline in production from existing wells in our
    operating regions, our future success depends on our ability to
    continually obtain new sources of natural gas supply, which
    depends in part on certain factors beyond our control. Any
    decrease in supplies of natural gas could adversely affect our
    revenues and operating income.
       29




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##### 



We
    rely on KMTPs Laredo-to-Katy pipeline to transport natural
    gas to our Houston Central processing plant, and an NGL pipeline
    owned by ONEOK Hydrocarbon to transport NGLs from our Paden
    processing plant. If one of these pipelines were to become
    unavailable, our cash flows, results of operations and financial
    condition could be adversely affected.
        We
    generally do not obtain reservoir engineering reports evaluating
    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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##### 



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 cash flows,
    results of operations and financial condition.
    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;
    international demand for LNG, oil and NGLs;
    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. 31




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##### 



Our
    hedging activities do not eliminate our exposure to fluctuations
    in commodity prices and interest rates and may reduce our cash
    flow and subject our earnings to increased
    volatility.
            Federal,
    state or local regulatory measures could adversely affect our
    business.
  and/or
   32




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##### 



and/or
    Montana v.
    Wyoming
   33




---



##### 



A
    change in the characterization of some of our assets by federal,
    state or local regulatory agencies could adversely affect our
    business.
    and/or
    We may
    incur significant costs and liabilities resulting from pipeline
    integrity programs and related repairs.
     34




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##### 



Because
    we handle natural gas, crude oil 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.
   35




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##### 



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.
    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
  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.
   36




---



##### 



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.
    We own
    interests in limited liability companies and a general
    partnership in which third parties also own interests, which may
    limit our ability to influence significant business decisions
    affecting these entities.
    
    62.5% interest in Webb/Duval Gatherers;
    majority interest in Southern Dome, LLC;
    51% interest in Bighorn Gas Gathering, L.L.C.; and
    37.04% interest in Fort Union Gas Gathering, L.L.C.     37




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##### 



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.
    Our
    cap on certain general and administrative expenses expired on
    December 31, 2007, and our pre-IPO investors are no longer
    required to reimburse us for certain amounts in excess of the
    cap, which could materially reduce the cash available for
    distribution 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.  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.
   38




---



##### 



Certain
    of our investors may sell units in the public market, which
    could reduce the market price of our outstanding common
    units.
  Form S-3
  
    1,184,557 common units to be issued upon conversion of
    Class C units we issued to the sellers in the Cimmarron
    acquisition;
    3,245,817 common units to be issued upon conversion of Class D
    units we issued to the sellers in the Cantera
    acquisition; and
    5,598,836 common units to be issued upon conversion of Class E
    units issued in our October 19, 2007 private placement.    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.
         39




---



##### 



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,
 40




---



##### 



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   41




---



##### 



Item 3.
    Legal
    Proceedings      Item 4.
    Submission
    of Matters to a Vote of Security Holders   42




---



##### 



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


CashCommon Units


DistributionHigh


Low


per Common Unit2007:Quarter Ended December 31

$
39.75


$
33.53


$
0.5100Quarter Ended September
    30(1)

$
44.81


$
33.25


$
0.4700Quarter Ended June 30

$
45.03


$
33.92


$
0.4400Quarter Ended March 31

$
35.10


$
28.85


$
0.42002006:Quarter Ended December 31

$
31.67


$
26.38


$
0.4000Quarter Ended September 30

$
27.40


$
23.37


$
0.3750Quarter Ended June 30

$
24.88


$
21.64


$
0.3375Quarter Ended March 31

$
22.48


$
19.05


$
0.3000     (1)
    
    Pursuant to the agreement among us and the accredited investors
    in our October 2007 private placement, common units we issued in
    the private placement were not eligible to receive distributions
    for the quarter ended September 30, 2007.       43




---



##### 



Distributions
  Common
    Units
    DistributionQuarter
    Ending(a)

Per Unit


Date Declared

Record Date

Payment Date

AmountMarch 31, 2006

$
0.3000


April 18, 2006

May 1, 2006

May 15, 2006

$
11,000June 30, 2006

$
0.3375


July 19, 2006

August 1, 2006

August 14, 2006

$
12,400September 30, 2006

$
0.3750


October 18, 2006

November 1, 2006

November 14, 2006

$
13,800December 31, 2006

$
0.4000


January 18, 2007

February 1, 2007

February 14, 2007

$
17,025March 31, 2007

$
0.4200


April 18, 2007

May 1, 2007

May 15, 2007

$
17,881June 30, 2007

$
0.4400


July 18, 2007

August 1, 2007

August 14, 2007

$
18,743September 30,
    2007(b)

$
0.4700


October 17, 2007

November 1, 2007

November 14, 2007

$
20,276December 31, 2007

$
0.5100


January 16, 2008

February 1, 2008

February 14, 2008

$
24,336     (a)
    
    Before February 14, 2007, the date on which our 3,519,126
    subordinated units (7,038,252 on a post-split basis) converted
    into common units, we paid cash distributions on all common and
    subordinated units then outstanding.(b)
    
    Pursuant to the agreement among us and the accredited investors
    in our October 2007 private placement, common units we issued in
    the private placement were not eligible to receive distributions
    for the quarter ended September 30, 2007.    One Quarter


Four QuartersCommon
    units(1)

$
24,336


$
97,342     (1)
    
    Includes restricted common units and phantom units issued under
    our Long-Term Incentive Plan, or LTIP. Distributions made on
    restricted units and phantom units issued to date are subject to
    the same vesting provisions as the restricted units and phantom
    units. As of February 1, 2008, we had 241,181 outstanding
    restricted units and 106,545 outstanding phantom units. Annual
    distributions related to these restricted units and phantom
    units are approximately $0.7 million. 44




---



##### 



one-for-one
  Class C
    Units
    Class D
    Units
  one-for-one
  Class E
    Units
    Unitholder
    Return Performance Presentation
    45




---



##### 



November 9,


December 31,2004


2004


2005


2006


2007Copano (CPNO)

$
100


$
126
(a)

$
180
(b)

$
288
(c)

$
367
(d)Alerian MLP Total Return Index (AMZX)

$
100


$
106


$
113


$
142


$
160S&P 500 (SPX)

$
100


$
104


$
107


$
122


$
126     (a)
    
    Based on the last sale price of our common units reported on the
    NASDAQ on December 31, 2004, as adjusted for the common
    unit split ($14.25).(b)
    
    Based on the last sale price of our common units reported on the
    NASDAQ on December 30, 2005, as adjusted for the common
    unit split ($19.525).(c)
    
    Based on the last sale price of our common units reported on the
    NASDAQ on December 29, 2006, as adjusted for the common
    unit split ($29.80).(d)
    
    Based on the last sale price of our common units reported on the
    NASDAQ on December 31, 2007 ($36.35).    Securities
    Authorized for Issuance Under Equity Compensation
    Plans
   46




---



##### 



Issuer
    Purchases of Equity Securities
    Recent
    Sales of Unregistered Securities
    Item 6.
    Selected
    Financial Data  Selected
    Historical Consolidated Financial and Operating Data
        Year Ended December 31,2007(1)


2006


2005(2)


2004


2003(In thousands, except per unit data)Summary of Operations Data:Revenues

$
1,141,660


$
860,272


$
747,743


$
437,656


$
384,571Cost of sales


934,726



672,184



643,652



386,155



353,376Operations and maintenance expenses


41,156



32,484



18,459



12,486



10,854Depreciation and amortization


39,967



31,993



17,052



7,287



6,091General and administrative expenses


34,638



26,535



18,156



9,217



5,849Taxes other than income


2,637



2,061



1,178



770



926Equity in (earnings) loss from unconsolidated
    affiliates(9)


(2,850
)


(1,297
)


(927
)


(419
)


127Operating income


91,386



96,312



50,173



22,160



7,348Interest income and other


2,854



1,706



640



85



43Interest and other financing costs


(29,351
)


(32,904
)


(20,461
)


(23,160
)


(12,108
)Income before income taxes


64,889



65,114



30,352



(915
)


(4,717
)Provision for income taxes


(1,714
)














Net income (loss)

$
63,175


$
65,114


$
30,352


$
(915
)

$
(4,717
)Basic net income (loss) per common
    unit(3)

$
1.48


$
1.77


$
1.20


$
(0.17
)

$
(3.11
)Diluted net income (loss) per common
    unit(3)

$
1.36


$
1.75


$
1.15


$
(0.17
)

$
(3.11
) 47




---



##### 



Year Ended December 31,2007(1)


2006


2005(2)


2004


2003(In thousands, except per unit data)Balance Sheet Data (at period end):Total assets

$
1,769,083


$
839,058


$
792,750


$
178,399


$
161,709Property, plant and equipment, net


694,727



566,927



532,320



119,683



117,032Payables to affiliates


1,351



123



189



127



1,371Long-term debt


630,773



255,000



398,000



57,000



57,898Redeemable preferred units


















60,982Members capital


894,136



472,586



281,803



82,356



(662
)Cash Flow Data:Net cash flow provided by (used in):Operating activities

$
128,218


$
91,679


$
280


$
17,697


$
15,296Investing activities


(727,052
)


(70,291
)


(491,708
)


(8,920
)


(6,192
)Financing activities


632,015



(7,201
)


509,710



(6,369
)


(9,633
)Other Financial Data:Total Segment Gross Margin:Oklahoma(4)(5)

$
115,099


$
95,614


$
40,683


$



$
Texas(6)(7)


121,935



91,121



63,048



51,501



31,195Rocky
    Mountains(8)


1,145















Segment gross margin


238,179



186,735



103,731



51,501



31,195Corporate and other


(31,245
)


1,353



360







Total Segment gross margin

$
206,934


$
188,088


$
104,091


$
51,501


$
31,195EBITDA(9)

$
134,207


$
130,011


$
67,865


$
29,532


$
13,482Adjusted
    EBITDA(10)

$
140,626


$
130,807


$
68,285


$
29,920


$
13,831Maintenance capital
    expenditures(11)

$
9,062


$
8,984


$
5,394


$
1,790


$
2,281Expansion capital
    expenditures(12)


884,290



53,298



487,578



7,130



3,911Total capital expenditures

$
893,352


$
62,282


$
492,972


$
8,920


$
6,192Cash distributions per common
    unit(3)

$
1.73


$
1.29


$
0.79


$
0.51


$
Operating Data:Oklahoma:(4)(5)Service throughput (Mcf/d)


165,059



147,166



132,011







Plant inlet volumes (Mcf/d)


117,423



102,556



87,977







NGLs produced (Bbls/d)


13,771



11,811



9,146







Crude pipeline throughput (Bbls/d)


2,417















Texas:Service throughput (Mcf/d)


608,171



543,303



567,002



591,431



585,410Pipeline throughput
    (Mcf/d)(6)


276,987



237,897



214,774



220,970



238,800Plant inlet volumes
    (Mcf/d)(6)(7)


535,142



495,600



530,346



529,040



479,127NGLs produced
    (Bbls/d)(6)(7)


17,496



14,740



13,066



15,373



7,280Rocky Mountains:Producer services throughput
    (Mcf/d)(8)


232,169















     (1)
    
    Our summary financial and operating data as of and for the year
    ended December 31, 2007 include results attributable to our
    Cimmarron from May 1, 2007 through December 31, 2007
    and Cantera from October 1, 2007 through December 31,
    2007.(2)
    
    Our summary financial and operating data as of and for the year
    ended December 31, 2005 include the results of our Oklahoma
    segment from August 1, 2005 (the date we acquired
    ScissorTail) through December 31, 2005.(3)
    
    Net income (loss) per unit is based on the weighted average of
    total equivalent units outstanding during the periods presented.
    Prior periods have been adjusted to reflect the
    two-for-one
    split of our outstanding common units effective March 30,
    2007. 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 2004
    and 2003 excludes incremental units related to warrants
    previously held by preferred unitholders and employee unit
    options because these equity securities 48




---



##### 



had an anti-dilutive effect as a result of losses reported by us
    for these periods. Cash distributions for 2004 relate to the
    distributions paid to the pre-IPO unitholders prior to our IPO
    and are based on equivalent units.(4)
    
    Plant inlet volumes and NGLs produced represent total volumes
    processed and produced by the Oklahoma segment at all plants,
    including our own plants and plants owned by third parties. For
    the year ended December 31, 2007, plant inlet volumes
    averaged 76,041 Mcf/d and NGLs produced averaged
    9,349 Bbls/d for plants owned by the Oklahoma segment. For
    the year ended December 31, 2006, plant inlet volumes
    averaged 67,131 Mcf/d and NGLs produced averaged
    7,989 Bbls/d for plants owned by the Oklahoma segment.(5)
    
    Excludes volumes associated with our interest in Southern Dome.
    For the year ended December 31, 2007, plant inlet volumes
    for Southern Dome averaged 5,093 Mcf/d and NGLs produced
    averaged 244 Bbls/d. For the year ended December 31,
    2006, plant inlet volumes for Southern Dome averaged
    2,004 Mcf/d and NGLs produced averaged 88 Bbls/d.(6)
    
    Excludes volumes associated with our interest in Webb Duval.
    Volumes transported by Webb Duval, net of intercompany volumes,
    were 82,755 Mcf/d, 102,691 Mcf/d, 106,826 Mcf/d,
    104,438 Mcf/d, and 95,341 Mcf/d for the years ended
    December 31, 2007, 2006, 2005, 2004 and 2003, respectively.(7)
    
    Plant inlet volumes and NGLs produced represent total volumes
    processed and produced by the Texas segment at all plants,
    including plants owned by the Texas segment and plants owned by
    third parties. Plant inlet volumes averaged 523,044 Mcf/d
    and NGLs produced averaged 16,317 barrels per day for the
    year ended December 31, 2007 for plants owned by the Texas
    segment. Plant inlet volumes averaged 495,600 Mcf/d and
    NGLs produced averaged 14,740 barrels per day for the year
    ended December 31, 2006 for plants owned by the Texas
    segment.(8)
    
    Producer services throughput represents volumes we purchased for
    resale, volumes gathered utilizing our firm capacity gathering
    agreements with Fort Union and firm capacity volumes under
    our transportation agreements with WIC that we have released to
    producers in the Powder River Basin. Excludes results and
    volumes associated with our interests in Bighorn and
    Fort Union. Volumes transported by Bighorn and
    Fort Union were 216,584 Mcf/d and 604,850 Mcf/d,
    respectively, for the period from October 1, 2007 through
    December 31 2007.(9)
    
    Under the equity method of accounting, these amounts include our
    equity in the (earnings) loss in affiliates.(10)
    
    We calculate Adjusted EBITDA by adding to EBITDA (i) the
    portion of each of our equity investees depreciation and
    amortization expense that is proportional to our ownership
    interest in each such equity investee, and (ii) the
    amortization expense attributable to the difference between our
    carried investment in each equity investee and our underlying
    equity in its net assets. We use Adjusted EBITDA to reflect the
    depreciation and amortization expense embedded in equity in
    earnings (loss) from unconsolidated affiliates. Adjusted EBITDA
    should not be considered an alternative to net income, operating
    income, cash flows from operating activities or any other
    measure of financial performance presented in accordance with
    GAAP.(11)
    
    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.(12)
    
    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. 49




---



##### 



Year Ended December 31,2007


2006


2005


2004


2003(In thousands)Reconciliation of total segment gross margin to operating income:Operating income

$
91,386


$
96,312


$
50,173


$
22,160


$
7,348Add:Operations and maintenance expenses


41,156



32,484



18,459



12,486



10,854Depreciation and amortization


39,967



31,993



17,052



7,287



6,091General and administrative expenses


34,638



26,535



18,156



9,217



5,849Taxes other than income


2,637



2,061



1,178



770



926Equity in (earnings) loss from unconsolidated affiliates


(2,850
)


(1,297
)


(927
)


(419
)


127Total segment gross margin

$
206,934


$
188,088


$
104,091


$
51,501


$
31,195Reconciliation of EBITDA and adjusted EBITDA to net income
    (loss):Net income (loss)

$
63,175


$
65,114


$
30,352


$
(915
)

$
(4,717
)Add:Depreciation and amortization


39,967



31,993



17,052



7,287



6,091Interest and other financing costs


29,351



32,904



20,461



23,160



12,108Provision for income taxes


1,714















EBITDA

$
134,207


$
130,011


$
67,865


$
29,532


$
13,482Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


4,589



(14
)


(21
)


(21
)


(21
)Copanos share of depreciation and amortization included in
    equity in (earnings) loss from unconsolidated affiliates


1,830



810



441



409



370Adjusted EBITDA

$
140,626


$
130,807


$
68,285


$
29,920


$
13,831Reconciliation of EBITDA and adjusted EBITDA to cash flows from
    operating activities:Cash flow provided by operating activities

$
128,218


$
91,679


$
280


$
17,697


$
15,296Add:Cash paid for interest and other financing costs


27,685



28,442



14,738



4,029



3,033Equity in earnings (loss) from unconsolidated affiliates


2,850



1,297



927



419



(127
)Distributions from unconsolidated affiliates


(3,706
)














Risk management assets


21,720



23,014



42,635







(Increase) decrease in working capital and other


(42,560
)


(14,421
)


9,285



7,387



(4,720
)EBITDA

$
134,207


$
130,011


$
67,865


$
29,532


$
13,482Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


4,589



(14
)


(21
)


(21
)


(21
)Copanos share of depreciation and amortization included in
    equity in (earnings) loss from unconsolidated affiliates


1,830



810



441



409



370Adjusted EBITDA

$
140,626


$
130,807


$
68,285


$
29,920


$
13,831  50




---



##### 



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
      
    Our Oklahoma segment provides midstream natural gas services in
    central and eastern Oklahoma, including 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, 2007 and 2006, this segment generated
    approximately 56% and 51%, respectively, of our total segment
    gross margin.
    Our Texas segment provides midstream natural gas services in
    southeastern and northern Texas, including gathering and
    intrastate transmission of natural gas, and related services
    such as compression, dehydration and marketing. Our Texas
    segment also provides natural gas processing, conditioning and
    treating and NGL fractionation and transportation through our
    Houston Central plant, Sheridan NGL pipeline and, beginning in
    2008, our Brenham NGL pipeline. In addition, our Texas segment
    owns a processing plant located in southwestern Louisiana. For
    the years ended December 31, 2007 and 2006, this segment
    generated approximately 58% and 48%, respectively, of our total
    segment gross margin.
    Our Rocky Mountains segment provides midstream natural gas
    services in the Powder River Basin of Wyoming, including
    gathering and treating of natural gas. The Rocky Mountains
    segment was established as a segment as a result of our
    acquisition of Cantera in October 2007. For the years ended
    December 31, 2007 and 2006, this segment generated
    approximately 1% and 0%, respectively, of our total segment
    gross margin, which represents margins derived from our producer
    services. The gross margin generated by this segment does not
    include results associated with our interests in Bighorn or
    Fort Union, which are reported as equity in earnings (loss)
    from unconsolidated affiliates.     51




---



##### 



How We
    Evaluate Our Operations
    Throughput Volumes.
    
    The volume of natural gas transported or gathered through our
    pipelines, which we call pipeline throughput; and
    The volume of natural gas delivered to our wholly owned
    processing plants by third-party pipelines, excluding any
    volumes already included in our pipeline throughput.      Segment Gross Margin.
 52




---



##### 



Operations and Maintenance
    Expenses.
  General and Administrative Expenses. page F-1
  Adjusted EBITDA.
 53




---



##### 




    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
  Flow and Transaction Monitoring Systems.
 54




---



##### 



Producer Activity Evaluation and Reporting.
  Imbalance Monitoring and Control. month-to-month
  Our
    Contracts
  percentage-of-proceeds percentage-of-index
    Fee-Based Arrangements.
  Percentage-of-Proceeds
    Arrangements. percentage-of-proceeds
 55




---



##### 



Percentage-of-Index
    Arrangements. percentage-of-index
  Keep-Whole with Fee Arrangements.
  agreed-upon
  Our Contracts with Kinder Morgan Texas
    Pipeline. 30-inch-diameter Laredo-to-Katy
    Laredo-to-Katy Laredo-to-Katy
 56




---



##### 



Our
    Long-Term Growth Strategy
    Acquisition Analysis.
  Capital Expenditure Analysis.
  Items Impacting
    Comparability of Our Financial Results
  Our
    Acquisitions
   57




---



##### 



Adoption
    of SFAS No. 123(R)
    Our
    Results of Operation
  Year Ended December 31,2007(1)


2006


2005(2)($ in thousands)Total segment gross
    margin(3)

$
206,934


$
188,088


$
104,091Operations and maintenance expenses


41,156



32,484



18,459Depreciation and amortization


39,967



31,993



17,052General and administrative expenses


34,638



26,535



18,156Taxes other than income


2,637



2,061



1,178Equity in earnings from unconsolidated affiliates


(2,850
)


(1,297
)


(927
)Operating income


91,386



96,312



50,173Interest and other financing costs, net


(26,497
)


(31,198
)


(19,821
)Income before income taxes


64,889



65,114



30,352Provision for income taxes


(1,714
)






Net income

$
63,175


$
65,114


$
30,352Total segment gross margin:Oklahoma(4)(5)

$
115,099


$
95,614


$
40,683Texas(6)(7)


121,935



91,121



63,048Rocky
    Mountains(8)


1,145







Segments gross margin


238,179



186,735



103,731Corporate and other


(31,245
)


1,353



360Total segment gross
    margin(3)

$
206,934


$
188,088


$
104,091Segment gross margin per unit:Oklahoma:Service throughput
    ($/MMBtu)(4)(5)

$
1.580


$
1.48


$
1.68Texas:Service throughput
    ($/MMBtu)(6)(7)

$
0.520


$
0.44


$
0.29Rocky Mountains:Producer services throughput
    ($/MMBtu)(8)

$
0.055







 58




---



##### 



Year Ended December 31,2007(1)


2006


2005(2)($ in thousands)Volumes:Oklahoma:(4)(5)Service throughput (MMBtu/d)


199,906



177,368



158,334Plant inlet volumes (MMBtu/d)


144,050



125,364



106,877NGLs produced (Bbls/d)


13,771



11,811



9,146Crude pipeline throughput (Bbls/d)


2,417







Texas:Service throughput (MMBtu/d)


645,724



573,141



597,888Pipeline throughput
    (MMBtu/d)(6)


299,484



254,886



232,280Plant inlet volumes
    (MMBtu/d)(6)(7)


567,306



522,465



561,085NGLs produced
    (Bbls/d)(6)(7)


17,496



14,740



13,066Rocky Mountains:Producer services throughput
    (MMBtu/d)(8)


224,525







Maintenance capital
    expenditures(9)

$
9,062


$
8,984


$
5,394Expansion capital
    expenditures(10)


884,290



53,298



487,578Total capital expenditures

$
893,352


$
62,282


$
492,972Operations and maintenance expenses:Oklahoma

$
20,711


$
17,185


$
5,917Texas


20,437



15,299



12,542Rocky Mountains


8







Total operations and maintenance expenses

$
41,156


$
32,484


$
18,459     (1)
    
    Our summary financial and operating data for the year ended
    December 31, 2007 include results attributable to Cimmarron
    acquisition from May 1, 2007 through December 31, 2007
    and Cantera (which comprises our entire Rocky Mountains segment)
    from October 1, 2007 through December 31, 2007. The
    results of operations from assets acquired in the Cimmarron
    acquisition are included in the Oklahoma segment and Texas
    segments.(2)
    
    Our summary financial and operating data for the year ended
    December 31, 2005 include the results of our Oklahoma
    segment from August 1, 2005 the date we acquired
    ScissorTail) through December 31, 2005.(3)
    
    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.(4)
    
    Plant inlet volumes and NGLs produced represent total volumes
    processed and produced by the Oklahoma segment at all plants,
    including our owned plants and plants owned by third parties.
    For the year ended December 31, 2007, Plant inlet volumes
    averaged 93,173 MMBtu/d and NGLs produced averaged
    9,349 Bbls/d for plants owned by the Oklahoma segment. For
    the year ended December 31, 2006, plant inlet volumes
    averaged 82,045 MMBtu/d and NGLs produced averaged
    7,989 Bbls/d for plants owned by the Oklahoma segment.(5)
    
    Excludes volumes associated with our interest in Southern Dome.
    For the year ended December 31, 2007, plant inlet volumes
    for Southern Dome averaged 6,061 MMBtu/d and NGLs produced
    averaged 244 Bbls/d. For the year ended December 31,
    2006, plant inlet volumes for Southern Dome averaged
    2,353 MMBtu/d and NGLs produced averaged 88 Bbls/d. 59




---



##### 



(6)
    
    Excludes results and volumes associated with our interest in
    Webb Duval. Volumes transported by Webb Duval, net of
    intercompany volumes, were 93,887 MMBtu/d,
    117,303 MMBtu/d and 121,864 MMBtu/d for the years
    ended December 31 2007, 2006 and 2005, respectively.(7)
    
    Plant inlet volumes and NGLs produced represent total volumes
    processed and produced by the Texas segment at all plants,
    including plants owned by the Texas segment and plants owned by
    third parties. Plant inlet volumes averaged 552,690 MMBtu/d
    and NGLs produced averaged 16,317 barrels per day for the
    year ended December 31, 2007 for plants owned by the Texas
    segment. Plant inlet volumes averaged 522,465 MMBtu/d and
    NGLs produced averaged 14,740 barrels per day for the year
    ended December 31, 2006 for plants owned by the Texas
    segment.(8)
    
    Producer services throughput represents volumes we purchased for
    resale, volumes gathered utilizing our firm capacity gathering
    agreements with Fort Union and firm capacity volumes under
    our transportation agreements with WIC that we have released to
    producers in the Powder River Basin. Excludes results and
    volumes associated with our interests in Bighorn and
    Fort Union. Volumes transported by Bighorn and
    Fort Union were 211,510 MMBtu/d and
    576,700 MMBtu/d, respectively, for the period from
    October 1, 2007 through December 31 2007.(9)
    
    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.(10)
    
    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.(11)
    
    Under the equity method of accounting, these amounts include our
    equity in the (earnings) loss in affiliates.  Year
    Ended December 31, 2007 Compared with Year Ended
    December 31, 2006
  Oklahoma Segment Gross Margin.
  Texas Segment Gross Margin.
  Rocky Mountains Segment Gross Margin.
 60




---



##### 



Corporate and Other. mark-to-market
  Operations and Maintenance
    Expenses.
  Depreciation and Amortization.
  General and Administrative Expenses.
  Interest Expense.
 61




---



##### 



Year
    Ended December 31, 2006 Compared with Year Ended
    December 31, 2005
  Oklahoma Segment Gross Margin.
  Texas Segment Gross Margin.
  Corporate and Other. mark-to-market
  Operations and Maintenance
    Expenses.
  Depreciation and Amortization.
  General and Administrative Expenses.
  Interest Expense.
 62




---



##### 



General
    Trends and Outlook
         63




---



##### 



Impact of
    Inflation
    Liquidity
    and Capital Resources
    Off-Balance Sheet Arrangements.
  Capital Requirements.
  
    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




---



##### 



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

$
630,000


$



$



$



$
630,000Interest(1)


316,806



46,095



92,191



88,611



89,909Gathering and transportation firm commitments


161,222



20,630



35,774



32,780



72,038Operating leases


7,260



3,322



2,906



1,032



Total contractual cash
    obligations(1)

$
1,115,288


$
70,047


$
130,871


$
122,423


$
791,947     (1)
    
    These amounts exclude estimates of the effect of our interest
    rate swap contracts on our future interest obligations. As of
    December 31, 2007, the fair value of our interest rate swap
    contracts, which expire between July 2010 and October 2012,
    totaled $4.1 million.      Cash
    Flows.
    Year Ended December 31,2007


2006


2005(In thousands)Net cash provided by operating activities

$
128,218


$
91,679


$
280Net cash used in investing activities


(727,052
)


(70,291
)


(491,708
)Net cash provided by (used in) financing activities


632,015



(7,201
)


509,710Net increase in cash and cash equivalents


33,181



14,187



18,282Cash and cash equivalents at beginning of year


39,484



25,297



7,015Cash and cash equivalents at end of year

$
72,665


$
39,484


$
25,297  65




---



##### 



Operating
    Activities:
  Year Ended December 31,2007


2006


2005(In thousands)Net income

$
63,175


$
65,114


$
30,352Depreciation and amortization


41,633



36,455



22,775Equity in earnings from unconsolidated affiliates


(2,850
)


(1,297
)


(927
)Distributions from unconsolidated affiliates


3,706







Equity compensation and other


4,318



2,086



1,309Cash used in working capital


18,236



(10,679
)


(53,229
)Net cash provided by operating activities

$
128,218


$
91,679


$
280         Investing Activities.
  11-mile 8-mile rights-of-way
 66




---



##### 



Financing Activities.
      Cash Distributions and Reserves.
  Description
    of Our Indebtedness
    Credit Ratings.
  Senior Secured Revolving Credit Facility. less-than-wholly
   67




---



##### 




    EBITDA to interest expense of not less than 2.5 to 1.0; and
    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 specified grace periods;
    failure to perform or otherwise comply with the covenants in the
    credit agreement or other loan documents, subject to certain
    grace periods in some cases;
    default on the payment of any other indebtedness in excess of
    $5 million, or 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; 68




---



##### 




    bankruptcy or insolvency events involving us or our subsidiaries;
    if Bighorn or Fort Union is unable to make a quarterly
    distribution to its members, our inability to demonstrate
    compliance with financial covenants within a specified period;
    the entry of, and failure to pay, one or more adverse judgments
    in excess of $5 million upon which enforcement proceedings
    are brought or are not stayed pending appeal; and
    a change of control (as defined in the Credit Facility).    Senior Notes. 1 8
          Year

Percentage2011


104.0625%2012


102.7083%2013


101.3542%2014 and thereafter


100.0000%       
    sell assets; 69




---



##### 




    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 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
  Accounting for Uncertainty in Income Taxes. Accounting for Uncertainty
    in Income Taxes-An Interpretation of FASB Statement
    No. 109. Accounting for Income Taxes
  Business Combinations. Business
    Combinations
  Fair Value Measurements. Fair Value
    Measurements.
  Fair Value Option for Financial Assets and Financial
    Liabilities. The Fair Value Option for
    Financial Assets and Financial Liabilities,
  Non-Controlling Interests in Consolidated Financial
    Statements  an Amendment of ARB No. 51. Non-Controlling Interests in Consolidated Financial
    Statements  an Amendment of ARB No. 51
 70




---



##### 



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;
    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.    Investments in Unconsolidated Affiliates Equity Method of Accounting.
  Revenue Recognition. agreed-upon
 71




---



##### 



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.    Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk    Commodity Price Risk.
 72




---



##### 



agreed-upon
         73




---



##### 



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 to hedge natural gas liquids produced or condensate
    collected by us or an entity or asset to be acquired by us if a
    binding purchase and sale agreement has been executed (a
    Pending Acquisition);
    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 a
    Pending Acquisition;
    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 a Pending
    Acquisition, 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 a Pending Acquisition.    
    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;
    Through December 31, 2008, notional volume must not exceed
    the projected requirements or output, as applicable, for the
    hedged period with respect to (i) the purchase of crude oil
    or NGL 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 NGL spread options permitted by
    the policy;
    After December 31, 2008, 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 NGL 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.        Oklahoma Segment.
 74




---



##### 



Texas Segment.
  Rocky Mountains Segment.
    Purchased
    CenterPoint East Natural Gas Puts
  Put Strike

Put Volumes(Per MMBtu)

(MMBtu/d)

Fair Value2008

$
7.75



5,000


$
2,080,0002009

$
6.95



5,000


$
1,205,000   Purchased
    HSC Index Natural Gas Call Spreads
  Call Strike(Per MMBtu)


Call VolumesBought


Sold


(MMBtu/d)


Fair Value2008

$
8.15


$
10.00



9,400


$
1,172,0002009

$
7.75


$
10.00



8,000


$
2,224,0002010

$
7.35


$
10.00



7,100


$
2,441,0002011

$
6.95


$
10.00



7,100


$
2,839,000   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 Value2008

$
0.5700



607


$



$
0.5650



607


$
(4,674,000
)2008

$
0.6250



2,900


$
1,000


$
0.6525



1,300


$
(8,302,000
)2009

$
0.5900



2,200


$
8,000


$
0.6025



1,100


$
(6,536,000
)2010

$
0.5550



1,600


$
9,000


$
0.5700



500


$
(2,851,000
)2011

$
0.5300



1,700


$
10,000


$
0.5450



500


$
(2,866,000
)  75




---



##### 



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 Value2008

$
0.8360



2,594


$
1,000


$
0.8700



745


$
(7,453,000
)2008

$
0.8975



1,100


$
2,0002008

$
1.0500



396


$
9,000


$







$
2009

$
0.8725



2,200


$
60,0002009

$
0.9650



1,000


$
81,000


$
1.0275



1,000


$
(6,184,000
)2010

$
0.8500



1,100


$
65,0002010

$
0.9460



700


$
107,000


$
0.9925



700


$
(4,106,000
)2011

$
0.8265



1,100


$
83,0002011

$
0.9340



700


$
139,000


$
0.9750



700


$
(4,041,000
)   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 Value2008

$
0.9900



622


$



$
1.0450



92


$
(1,100,000
)2008

$
1.0900



250


$
2009

$
1.0600



450


$
10,0002009

$
1.1600



100


$
6,000


$
1.2425



100


$
(733,000
)2010

$
1.0350



300


$
14,0002010

$
1.1145



100


$
10,000


$
1.2025



100


$
(699,000
)2011

$
1.0205



300


$
20,0002011

$
1.1100



100


$
14,000


$
1.1800



100


$
(691,000
)   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 Value2008

$
0.9875



810


$



$
1.0400



271


$
(3,112,000
)2008

$
1.0800



300


$
2009

$
1.0525



700


$
3,0002009

$
1.1400



400


$
6,000


$
1.2275



400


$
(2,752,000
)2010

$
1.0300



300


$
3,0002010

$
1.1000



200


$
5,000


$
1.1850



200


$
(1,313,000
)2011

$
1.0205



300


$
4,0002011

$
1.0850



200


$
6,000


$
1.1700



200


$
(1,280,000
)   Purchased
    Non-TET Natural Gasoline Puts and Entered into Swaps
  Put


SwapStrike


Volumes





Price


Volumes(per gallon)


(Bbls/d)


Fair Value


(per gallon)


(Bbls/d)


Fair Value2008

$
1.4850



300


$
4,000


$
1.5850



300


$
(2,170,000
)2009

$
1.4400



200


$
18,000


$
1.5400



200


$
(1,219,000
)2010

$
1.4080



300


$
42,000


$







$
2011

$
1.4100



300


$
56,000


$







$
  76




---



##### 



Purchased
    WTI Crude Oil Puts as Listed Below:
  Put Strike


Put Volumes(per barrel)


(Bbls/d)


Fair Value2008

$
55.00



1,000


$
6,0002008

$
60.00



700


$
13,0002009

$
55.00



1,000


$
89,0002009

$
60.00



500


$
101,0002010

$
55.00



1,000


$
214,0002010

$
60.00



400


$
166,0002011

$
55.00



1,000


$
317,0002011

$
60.00



400


$
225,000     Interest Rates.
      Risk Management Oversight.
  Credit Risk.
 77




---



##### 



Item 8.
    Financial
    Statements and Supplementary Data  pages F-1 F-54
  Item 9.
    Changes
    in and Disagreements with Accountants on Accounting and
    Financial Disclosure   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
   78




---



##### 



MANAGEMENTS
    ANNUAL REPORT ON INTERNAL CONTROL
    OVER FINANCIAL REPORTING
    AS OF DECEMBER 31, 2007
  Rules 13a-15(f) 15d-15(f) Rules 13a-15(f))
          Rules 13a-15(f) 15d-15(f)
  /s/  John
    R. Eckel, Jr.John
    R. Eckel, Jr.
    Chairman of the Board of Directors and Chief Executive Officer

/s/  Matthew
    J. AssiffMatthew
    J. Assiff
    Senior Vice President and Chief Financial Officer  79




---



##### 



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
     Internal Control  Integrated Framework
        Internal Control  Integrated Framework
 80




---



##### 



Item 9B.Other
    Information   81




---



##### 



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   82




---



##### 



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

Description2
.1

Purchase Agreement dated as of August 31, 2007 among Copano
    Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and
    Cantera Resources Holdings LLC (incorporated by reference to
    Exhibit 2.1 to Current Report on Form 8-K filed October 25,
    2007).2
.2

Contribution Agreement dated as of April 5, 2007 by and among
    Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron
    Transportation, L.L.C. and Copano Energy, L.L.C. (incorporated
    by reference to Exhibit 2.1 to Current Report on Form 8-K filed
    April 11, 2007).3
.1

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

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

Third Amended and Restated Limited Liability Company Agreement
    of Copano Energy, L.L.C. (incorporated by reference to Exhibit
    3.1 to Current Report on Form 8-K filed April 30, 2007).3
.4

Amendment No. 1 to Third Amended and Restated Limited Liability
    Company Agreement of Copano Energy, L.L.C. (incorporated by
    reference to Exhibit 3.1 to Current Report on Form 8-K filed May
    4, 2007).3
.5

Amendment No. 2 to Third Amended and Restated Limited Liability
    Company Agreement of Copano Energy, L.L.C. dated October 19,
    2007 (incorporated by reference to Exhibit 3.1 to Current Report
    on Form 8-K filed October 25, 2007).3
.6

Amendment No. 3 to Third Amended and Restated Limited Liability
    Company Agreement of Copano Energy, L.L.C., dated October 19,
    2007 (incorporated by reference to Exhibit 3.2 to Current Report
    on Form 8-K filed October 25, 2007).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 May 1, 2007, by and
    among Copano Energy, L.L.C. and Cimmarron Gathering GP, LLC,
    Taos Gathering, LP and Cimmarron Transportation, LLC
    (incorporated by reference to Exhibit 4.1 to Current Report on
    Form 8-K filed May 4, 2007).4
.5

Registration Rights Agreement by and between Copano Energy,
    L.L.C. and Cantera Resources Holdings LLC, dated October 19,
    2007 (incorporated by reference to Exhibit 4.1 to Current Report
    on Form 8-K filed October 25, 2007).4
.6

Registration Rights Agreement by and among Copano Energy, L.L.C.
    and the Purchasers, dated October 19, 2007 (incorporated by
    reference to Exhibit 4.2 to Current Report on Form 8-K filed
    October 25, 2007).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

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). 83




---



##### 



Number

Description10
.3

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
.4

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
.5

First Amendment to Administrative and Operating Services
    Agreement (incorporated by reference to Exhibit 10.1 to
    Quarterly Report on Form 10-Q filed November 9, 2007).10
.6

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
.7

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
.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.,
    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
.9

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
.10

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
.11

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
.12

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
.13

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
.14

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
.15

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
.16

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
.17

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
.18

2004 Form of Restricted Unit Grant (Directors) (incorporated by
    reference to Exhibit 10.1 to Current Report on Form 8-K filed
    December 15, 2004).10
.19

2004 Form of Unit Option Grant (incorporated by reference to
    Exhibit 10.17 to Quarterly Report on Form 10-Q filed December
    21, 2004).10
.20

2005 Form of Restricted Unit Grant (Employees) (incorporated by
    reference to Exhibit 4.4 to Registration Statement on Form S-8
    filed February 11, 2005).10
.21

2005 Form of Unit Option Grant (incorporated by reference to
    Exhibit 4.5 to Registration Statement on Form S-8 filed February
    11, 2005).10
.22

Form of Unit Option Grant (ScissorTail Energy, LLC Officers)
    (incorporated by reference to Exhibit 10.37 to Quarterly Report
    on Form 10-Q filed August 15, 2005). 84




---



##### 



Number

Description10
.23

Form of Restricted Unit Grant (ScissorTail Energy, LLC Officers)
    (incorporated by reference to Exhibit 10.38 to Quarterly Report
    on Form 10-Q filed August 15, 2005).10
.24

2006 Form of Restricted Unit Grant (Directors) (incorporated by
    reference to Exhibit 10.3 to Current Report on Form 8-K filed
    May 30, 2006).10
.25

2006 Form of Unit Option Grant (Employees) (incorporated by
    reference to Exhibit 10.2 to Current Report on Form 8-K filed
    May 30, 2006).10
.26

2006 Form of Restricted Unit Grant (Employees) (incorporated by
    reference to Exhibit 10.4 to Current Report on Form 8-K filed
    May 30, 2006).10
.27

November 2006 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
.28

2007 Form of Phantom Unit Grant (incorporated by reference to
    Exhibit 10.1 to Current Report on Form 8-K filed June 18, 2007).10
.29

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
.30

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).10
.31

2008 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 27, 2008).10
.32

Form of Indemnification Agreement (incorporated by reference to
    Exhibit 10.1 to Current Report on Form 8-K filed November 2,
    2005).10
.33

Copano Energy, L.L.C. Change in Control Severance Plan
    (incorporated by reference to Exhibit 10.1 to Current Report on
    Form 8-K filed December 18, 2007).10
.34

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
.35

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
.36

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
.37

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
.38

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
.39

Amended and Restated Credit 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
.40*

First Amendment to Amended and Restated Credit Agreement, dated
    October 19, 2007.12
.1*

Statement of Computation of Ratios of Earnings to Fixed Changes.21
.1*

List of Subsidiaries.23
.1*

Consent of Deloitte & Touche LLP.23
.2*

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. 85




---



##### 



Number

Description32
.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   86




---



##### 



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)

February 29, 2008/s/  Matthew
    J. AssiffMatthew
    J. Assiff

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

February 29, 2008/s/  Lari
    ParadeeLari
    Paradee

Vice President and Controller (Principal Accounting Officer)

February 29, 2008/s/  James
    G. CrumpJames
    G. Crump

Director

February 29, 2008/s/  Ernie
    L. DannerErnie
    L. Danner

Director

February 29, 2008/s/  Michael
    L. JohnsonMichael
    L. Johnson

Director

February 29, 2008/s/  Scott
    A. GriffithsScott
    A. Griffiths

Director

February 29, 2008/s/  T.
    William PorterT.
    William Porter

Director

February 29, 2008/s/  William
    L. ThackerWilliam
    L. Thacker

Director

February 29, 2008  87




---



##### 



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


F-2Consolidated Balance Sheets as of December 31, 2007 and 2006


F-3Consolidated Statements of Operations for the years ended
    December 31, 2007, 2006 and 2005


F-4Consolidated Statements of Cash Flows for the years ended
    December 31, 2007, 2006 and 2005


F-5Consolidated Statements of Members Capital and
    Compreshensive Income (Loss) for the years ended
    December 31, 2007, 2006 and 2005 Notes to Consolidated
    Financial Statements


F-6Bighorn Gas Gathering, L.L.C. Financial Statements:Independent Auditors Report


F-51Balance Sheet as of December 31, 2007


F-52Statement of Operations for the period from October 1, 2007
    through December 31, 2007


F-53Statement of Cash Flows for the period from October 1, 2007
    through December 31, 2007


F-54Statement of Members Equity for the period from
    October 1, 2007 through December 31, 2007


F-55Notes to Financial Statements


F-56  F-1




---



##### 



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM   
          Internal Control  Integrated Framework
  
   
 F-2




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    BALANCE SHEETS
  December 31,2007


2006(In thousands,except unit information)ASSETSCurrent assets:Cash and cash equivalents

$
72,665


$
39,484Accounts receivable, net


127,534



67,095Risk management assets


3,289



13,973Prepayments and other current assets


3,881



3,166Total current assets


207,369



123,718Property, plant and equipment, net


694,727



566,927Intangible assets, net


200,546



93,372Investment in unconsolidated affiliates


632,725



19,378Risk management assets


10,598



23,826Other assets, net


23,118



11,837Total assets

$
1,769,083


$
839,058LIABILITIES AND MEMBERS CAPITALCurrent liabilities:Accounts payable

$
147,046


$
91,668Notes payable






1,495Accrued interest


11,319



6,261Accrued tax liability


3,919



Risk management liabilities


27,710



944Other current liabilities


12,931



5,354Total current liabilities


202,925



105,722Long-term debt (includes $773 bond premium as of
    December 31, 2007)


630,773



255,000Deferred tax provision


1,231



Risk management and other noncurrent liabilities


40,018



5,750Commitments and contingencies (Note 13)Members capital:Common units, no par value, 47,366,048 units and
    35,190,590 units issued and outstanding as of
    December 31, 2007 and 2006, respectively


661,585



480,797Class C units, no par value, 1,184,557 units and
    0 units issued and outstanding as of December 31, 2007
    and 2006, respectively


40,492



Class D units, no par value, 3,245,817 units and
    0 units issued and outstanding as of December 31, 2007
    and 2006, respectively


112,454



Class E units, no par value, 5,598,839 units and
    0 units issued and outstanding as of December 31, 2007
    and 2006, respectively


175,634



Subordinated units, no par value, 7,038,252 units issued
    and outstanding as of December 31, 2006






10,379Paid-in capital


23,773



10,585Accumulated (deficit) earnings


(7,867
)


2,918Other comprehensive loss


(111,935
)


(32,093
)894,136



472,586Total liabilities and members capital

$
1,769,083


$
839,058    F-3




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    STATEMENTS OF OPERATIONS
  Year Ended December 31,2007


2006


2005(In thousands,except per unit information)Revenue:Natural gas sales

$
518,431


$
448,054


$
496,906Natural gas liquids sales


491,432



369,892



224,695Crude oil sales


77,142







Transportation, compression and processing fees


22,306



16,232



15,110Condensate and other


32,349



26,094



11,032Total revenue


1,141,660



860,272



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


853,964



669,158



641,315Cost of crude oil purchases


73,814







Transportation


6,948



3,026



2,337Operations and maintenance


41,156



32,484



18,459Depreciation and amortization


39,967



31,993



17,052General and administrative


34,638



26,535



18,156Taxes other than income


2,637



2,061



1,178Equity in earnings from unconsolidated affiliates


(2,850
)


(1,297
)


(927
)Total costs and expenses


1,050,274



763,960



697,570Operating income


91,386



96,312



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


2,854



1,706



640Interest and other financing costs


(29,351
)


(32,904
)


(20,461
)Income before income taxes


64,889



65,114



30,352Provision for income taxes


(1,714
)






Net income

$
63,175


$
65,114


$
30,352Basic net income per common unit:Net income per common unit

$
1.48


$
1.77


$
1.20Weighted average number of common units


42,456



29,752



16,984Diluted net income per common unit:Net income per common unit

$
1.36


$
1.75


$
1.15Weighted average number of common units


46,516



30,180



26,508Basic net income per subordinated unit:Net income per subordinated unit

$
0.21


$
1.77


$
1.20Weighted average number of subordinated units


848



7,038



7,038Diluted net income per subordinated unit:Net income per subordinated unit

$
0.21


$
1.76


$
1.20Weighted average number of subordinated units


848



7,038



7,038Basic net income per Class B unit:Net income per Class B unit

$



$



$
0.66Weighted average number of Class B units










2,303Diluted net income per Class B unit:Net income per Class B unit

$



$



$
0.39Weighted average number of Class B units










2,303    F-4




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED
    STATEMENTS OF CASH FLOWS
  Year Ended December 31,2007


2006


2005(In thousands)Cash Flows From Operating Activities:Net income

$
63,175


$
65,114


$
30,352Adjustments to reconcile net income to net cash provided by
    operating activities:Depreciation and amortization


39,967



31,993



17,052Amortization of debt issue costs


1,666



4,462



5,723Equity in earnings from unconsolidated affiliates


(2,850
)


(1,297
)


(927
)Distributions from unconsolidated affiliates


3,706







Equity-based compensation


3,223



1,910



1,283Deferred tax provision


1,231







Other noncash items


(136
)


176



26Changes in assets and liabilities, net of acquisitions:Accounts receivable


(34,890
)


16,459



(16,725
)Prepayments and other current assets


(204
)


1,372



2,771Risk management assets


(21,720
)


(23,014
)


(42,635
)Accounts payable


38,232



(6,867
)


19,720Other current liabilities


36,818



1,371



(16,360
)Net cash provided by operating activities


128,218



91,679



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


(80,898
)


(49,033
)


(9,602
)Additions to intangible assets


(3,406
)


(1,237
)


(95,586
)Acquisitions, net of cash acquired


(641,097
)


(9,074
)


(384,154
)Investment in unconsolidated affiliates


(1,727
)


(10,438
)


(2,722
)Distributions from unconsolidated affiliates


676







Escrow cash










1,001Other


(600
)


(509
)


(645
)Net cash used in investing activities


(727,052
)


(70,291
)


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


(288,000
)


(506,500
)


(94,000
)Proceeds from long-term debt


663,781



363,500



435,000Repayment of short-term notes payable


(1,495
)


(1,842
)


(1,207
)Deferred financing costs


(10,677
)


(7,035
)


(9,802
)Distributions to unitholders


(73,629
)


(46,977
)


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






162,725



Proceeds from private placement of common units


157,125



25,000



64,499Proceeds from private placement of Class B units










135,503Proceeds from private placement of Class E units


177,875







Capital contributions from Pre-IPO Investors (Note 8)


9,965



4,607



4,068Equity offering costs


(4,741
)


(1,057
)


(1,074
)Proceeds from option exercises


1,811



378



89Net cash provided by (used in) financing activities


632,015



(7,201
)


509,710Net increase in cash and cash equivalents


33,181



14,187



18,282Cash and cash equivalents, beginning of year


39,484



25,297



7,015Cash and cash equivalents, end of year

$
72,665


$
39,484


$
25,297    F-5




---



##### 






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

Class B

Class C

Class D

Class E

Subordinated



Accumulated



Other



TotalNumber

Common

Number

Class B

Number

Class C

Number

Class D

Number

Class E

Number

Subordinated

Paid-in

Earnings

Deferred

Comprehensive



Comprehensiveof Units

Units

of Units

Units

of Units

Units

of Units

Units

of Units

Units

of Units

Units

Capital

(Deficit)

Compensation

Loss

Total

IncomeBalance, December 31, 2004


14,112


$
94,325






$







$







$







$




7,038


$
10,379


$



$
(21,927
)

$
(421
)

$




82,356Capital contributions from Pre-IPO Investors


















































4,068















4,068


$
Private placement of units


4,164



64,499



9,662



135,503



















































200,002



Equity offering costs






(777
)






(858
)


















































(1,635
)


Conversion of Class B units into common units


9,662



134,645



(9,662
)


(134,645
)






















































Distributions to unitholders






















































(23,366
)










(23,366
)


Option exercises


10



89



























































89



Issuance of restricted units


254



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


28,202



297,592



































7,038



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


1,418



25,000



























































25,000



Issuance of common units to public


5,750



169,941



























































169,941



Equity offering costs






(8,165
)


























































(8,165
)


Distributions to unitholders






















































(47,255
)










(47,255
)


Option exercises


30



378



























































378



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


(277
)


(3,949
)


















































3,949











Equity-based compensation


















































1,910















1,910



Vested restricted units


68



































































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


35,191



480,797



































7,038



10,379



10,585



2,918







(32,093
)


472,586Capital contributions from Pre-IPO Investors


















































9,965















9,965



Conversion of subordinated units into common units


7,038



10,379



































(7,038
)


(10,379
)






















Private placement of units


4,533



157,125











1,579



54,000



3,246



112,500



5,599



177,875



























501,500



Offering costs






(2,027
)














(8
)






(46
)






(2,241
)


























(4,322
)


Conversion of Class C units into common units


395



13,500











(395
)


(13,500
)














































Distributions to unitholders






















































(73,960
)










(73,960
)


Option exercises


115



1,811



























































1,811



Equity-based compensation


















































3,223















3,223



Vested restricted units


94



































































Net income






















































63,175











63,175



63,175Derivative settlements reclassified to income






























































8,296



8,296



8,296Unrealized loss-change in fair value of derivatives






























































(88,138
)


(88,138
)


(88,138
)Comprehensive loss





































































$
(16,667
)Balance, December 31, 2007


47,366


$
661,585






$




1,184


$
40,492



3,246


$
112,454



5,599


$
175,634






$



$
23,773


$
(7,867
)

$



$
(111,935
)

$
894,136    F-6




---



##### 





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
      Investments
    in Unconsolidated Affiliates
   F-7




---



##### 



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, 2007

$
64


$
69


$
(2
)

$
131Year ended December 31, 2006


64



42



(42
)


64Year ended December 31, 2005


356



(285
)


(7
)


64   Property,
    Plant and Equipment
   F-8




---



##### 



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


15-30 yearsGas processing plants and equipment


20-30 yearsOther property and equipment


3-7 years     Intangible
    Assets
  2008  2009  2010  2011  2012 
  December 31,2007


2006Rights-of-way and easements, at cost

$
104,428


$
60,931Less accumulated amortization for rights-of-way and easements


(8,923
)


(6,520
)Contracts


112,385



42,444Less accumulated amortization for contracts


(7,833
)


(4,009
)Customer relationship


725



725Less accumulated amortization for customer relationship


(236
)


(199
)Intangible assets, net

$
200,546


$
93,372     Asset
    Impairment
   F-9




---



##### 



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
    Asset
    Retirement Obligations
  Accounting
    for Asset Retirement Obligations.
    Accounting for Conditional Asset
    Retirement Obligations, an interpretation of FASB Statement
    No. 143. and/or and/or
 F-10




---



##### 



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


2005Natural gas sales revenue:As reported

$
448,054


$
496,906As if presented net under Issue
    04-13

$
448,054


$
464,798Cost of natural gas and natural gas liquids:As reported

$
669,158


$
641,315As if presented net under Issue
    04-13

$
669,158


$
609,207     Derivatives
  Accounting for Derivative
    Instruments and Hedging Activities,
 F-11




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)        Income
    Taxes
    Accounting
    for Income Taxes,
 F-12




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)  Accounting
    for Uncertainty in Income Taxes  an Interpretation of
    FASB Statement No. 109.
    Net
    Income Per Unit
  Earnings Per Share, No. 03-6 03-6), Participating Securities and the Two-Class Method
    under Financial Accounting Standards Board Statement
    No. 128  03-6
   F-13




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Year Ended December 31,2007


2006


2005(In thousands, except per unit information)Net income

$
63,175


$
65,114


$
30,352Less net income attributable to subordinated units


(175
)


(12,457
)


(8,446
)Less net income attributable to Class B units










(1,526
)Net income available  basic common units


63,000



52,657



20,380Net income reallocated from subordinated units


175



39



8,446Net income reallocated from to Class B units










1,526Net income available  diluted common units

$
63,175


$
52,696


$
30,352Basic weighted average common units


42,456



29,752



16,984Dilutive weighted average common units**


46,516



30,180



26,508Basic net income per common unit

$
1.48


$
1.77


$
1.20Diluted net income per common unit**

$
1.36


$
1.75


$
1.15     **
    
    Our potentially dilutive common equity includes the following:  Year Ended December 31,2007


2006


2005(In thousands)Employee options


537



318



183Restricted units


138



110



Class C units


743







Class D units


658







Class E units


1,135







   Share-Based
    Payment
  Share-Based Payment, Accounting for Stock
    Issued to Employees,
   F-14




---



##### 



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  Business
    Combinations
  Business Combinations
  Fair
    Value Measurements
  Fair Value Measurements. Accounting for Derivative Instruments and Hedging
    Activities,
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
  Non-Controlling
    Interests in Consolidated Financial Statements  an
    Amendment of ARB No. 51
  Non-Controlling Interests in Consolidated Financial
    Statements  an Amendment of ARB No. 51
  Note 4 
    Acquisitions  Acquisition
    of Cantera Natural Gas, LLC
   F-15




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)        Purchase price for the Cantera Acquisition

$
675,000Net working capital adjustments


45,762Acquisition costs


12,013Total purchase price for the Cantera Acquisition

$
732,775     Cash and cash equivalents

$
37,175Accounts receivable


14,149Prepayments and other current assets


117Property, plant and equipment


13,551Intangibles


62,512Other assets


81Investment in unconsolidated affiliates


613,448Accounts payable


(4,289
)Other current liabilities


(3,812
)Other noncurrent liabilities


(157
)$
732,775    F-16




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)  Acquisition
    of Cimmarron Gathering, LP
        Purchase price for the Cimmarron Acquisition

$
110,000Net working capital adjustments


973Acquisition costs


1,494Total purchase price for the Cimmarron Acquisition

$
112,467     Cash and cash equivalents

$
3,257Accounts receivable


11,027Prepayments and other current assets


393Property, plant and equipment


62,558Intangibles


48,339Other assets


995Investment in unconsolidated affiliates


77Accounts payable


(14,179
)$
112,467      F-17




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)    Year Ended December 31,2007


2006(In thousands, except per unit information)Pro Forma Earnings Data:Revenue

$
1,308,916


$
1,179,073Costs and expenses

$
1,205,552


$
1,082,054Equity in earnings from unconsolidated affiliates

$
3,134


$
2,412Operating income

$
103,364


$
97,019Income before extraordinary items

$
54,427


$
45,850Net income

$
54,427


$
45,850Basic net income per unit:As reported units outstanding


42,456



29,752Pro forma units outstanding


46,301



34,581As reported net income per unit

$
1.48


$
1.77Pro forma net income per unit

$
1.17


$
1.10Diluted net income per unit:As reported units outstanding


46,516



30,180Pro forma units outstanding


57,659



44,886As reported net income per unit

$
1.36


$
1.75Pro forma net income per unit

$
0.94


$
0.84Basic net income per subordinated unit:As reported units outstanding


848



7,038Pro forma units outstanding


848



7,038As reported net income per unit

$
0.21


$
1.77Pro forma net income per unit

$
0.21


$
1.10Diluted net income per subordinated unit:As reported units outstanding


848



7,038Pro forma units outstanding


848



7,038As reported net income per unit

$
0.21


$
1.76Pro forma net income per unit

$
0.21


$
1.10   Acquisition
    of ScissorTail Energy, LLC
   F-18




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 5 
    Property,
    Plant and Equipment and Asset Retirement Obligations    December 31,2007


2006Property, plant and equipment, at costPipelines and equipment

$
647,188


$
531,509Gas processing plant and equipment


96,448



77,556Construction in progress


42,452



18,386Office furniture and equipment


5,203



4,902791,291



632,353Less accumulated depreciation and amortization


(96,564
)


(65,426
)Property, plant and equipment, net

$
694,727


$
566,927   Asset retirement obligations.
    Asset 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


340Asset retirement obligations incurred in 2007


188Accretion of FIN 47 for conditional obligations


27Asset retirement obligation liability balance, December 31,
    2007

$
555       Note 6 
    Investment
    in Unconsolidated Affiliates   F-19




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment
    in Unconsolidated Affiliates (Continued)      Webb
    Duval
      Year Ended December 31,2007


2006


2005Operating revenue

$
3,802


$
5,961


$
6,809Operating expenses


(826
)


(3,733
)


(4,837
)Depreciation


(768
)


(743
)


(702
)Net income


2,208



1,485



1,270Ownership %


62.5
%


62.5
%


62.5
%1,380



928



793Copanos share of management fee charged to Webb Duval


132



120



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


21



21



21Equity in earnings from Webb Duval

$
1,533


$
1,069


$
934Distributions from Webb Duval

$
2,401


$



$
Current assets

$
1,920


$
4,595Noncurrent assets


7,426



8,104Current liabilities


(779
)


(2,502
)Noncurrent liabilities


(51
)


(47
)Net assets

$
8,516


$
10,150   Southern
    Dome
   F-20




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment
    in Unconsolidated Affiliates (Continued)      Year Ended December 31,2007


2006


2005Operating revenue

$
16,198


$
6,105


$
1,289Operating expenses


(13,683
)


(5,468
)


(1,296
)Depreciation


(736
)


(497
)


(3
)Net income


1,779



140



(10
)Ownership
    %(1)


69.5
%


69.5
%


69.5
%1,236



97



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


173



137



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


(9
)


(6
)


Equity in earnings from Southern Dome

$
1,400


$
228


$
(7
)Distributions from Southern Dome

$
1,981


$



$
Current assets

$
4,434


$
2,516Noncurrent assets


16,802



17,507Current liabilities


(4,473
)


(2,189
)Net assets

$
16,763


$
17,834     (1)
    
    Represents Copanos right to distributions from Southern
    Dome.  Bighorn
    Gas Gathering and Fort Union Gas Gathering
     F-21




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment
    in Unconsolidated Affiliates (Continued)    Period from October 1, 2007Through December 31, 2007Bighorn


Fort UnionOperating revenue

$
7,809


$
9,065Operating expenses


(2,687
)


(864
)Depreciation


(994
)


(895
)Interest expense and other


24



(1,124
)Net income


4,152



6,182Ownership %


51
%


37.04
%2,118



2,290Copanos share of management fee charged to Bighorn and
    Fort Union


58



8Amortization of difference between the carried investment and
    the underlying equity in net assets


(2,995
)


(1,606
)Equity in (loss) earnings

$
(819
)

$
692Distributions

$
2,624


$
1,704Current assets

$
6,981


$
12,812Noncurrent assets


97,570



141,430Current liabilities


(1,923
)


(22,895
)Noncurrent liabilities






(87,357
)Net assets

$
102,628


$
43,990    Note 7 
    Long-Term
    Debt    December 31,2007


2006Long-term debt:Credit Facility

$
280,000


$
30,000Senior Notes:8.125% senior notes due 2016


350,000



225,000Unamortized bond premium


773



Total Senior Notes


350,773



225,000Total

$
630,773


$
255,000   Senior
    Secured Revolving Credit Facility
   F-22




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term
    Debt (Continued)             F-23




---



##### 



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 2.5 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 specified grace periods;
    failure to perform or otherwise comply with the covenants in the
    credit agreement or other loan documents, subject to certain
    grace periods in some cases;
    default on the payment of any other indebtedness in excess of
    $5 million, or 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;
    if Bighorn or Fort Union is unable to make a quarterly
    distribution to its members, our inability to demonstrate
    compliance with financial covenants within a specified period;
    the entry of, and failure to pay, one or more adverse judgments
    in excess of $5 million upon which enforcement proceedings
    are brought or are not stayed pending appeal; and
    a change of control (as defined in the Credit Facility).    Senior
    Notes
     F-24




---



##### 



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 liens;
    enter into agreements that restrict distributions or other
    payments from our restricted subsidiaries to us; F-25




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term
    Debt (Continued)   
    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-26




---



##### 






COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
  Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING BALANCE SHEETS
  December 31, 2007

December 31, 2006Investment 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

$
10,018


$



$
62,647


$



$



$
72,665


$
1,286


$



$
38,198


$



$



$
39,484Accounts receivable, net


476







127,058











127,534



32







120,057







(52,994
)


67,095Intercompany receivable


37,027







(37,027
)














24,908







(71,028
)






46,120



Risk management assets










3,289











3,289











13,973











13,973Prepayments and other current assets


877







3,004











3,881



44







3,122











3,166Total current assets


48,398







158,971











207,369



26,270







104,322







(6,874
)


123,718Property, plant and equipment, net


264







694,463











694,727



299







566,628











566,927Intangible assets, net










200,546











200,546











93,372











93,372Investment in unconsolidated affiliates










632,725



632,725



(632,725
)


632,725











19,378



19,378



(19,378
)


19,378Investment in consolidated subsidiaries


1,473,187















(1,473,187
)






674,105















(674,105
)


Risk management assets










10,598











10,598











23,826











23,826Other assets, net


17,589







5,529











23,118



8,577







3,260











11,837Total assets

$
1,539,438


$



$
1,702,832


$
632,725


$
(2,105,912
)

$
1,769,083


$
709,251


$



$
810,786


$
19,378


$
(700,357
)

$
839,058LIABILITIES AND MEMBERS/PARTNERS CAPITALCurrent liabilities:Accounts payable

$
35


$



$
147,011


$



$
(
)

$
147,046


$
434


$



$
130,919


$



$
(39,685
)

$
91,668Intercompany payable


























(26,291
)






(6,520
)






32,811



Notes payable


































1,495











1,495Accrued interest


11,319



















11,319



6,261



















6,261Accrued tax liability


483







3,436











3,919























Risk management liabilities










27,710











27,710











944











944Other current liabilities


882







12,049











12,931



550







4,804











5,354Total current liabilities


12,719







190,206











202,925



(19,046
)






131,642







(6,874
)


105,722Long-term debt


630,773



















630,773



255,000



















255,000Deferred tax provision


1,231



















1,231























Risk management and other noncurrent liabilities


579







39,439











40,018



711







5,039











5,750Members/Partners capital:Common units


661,585



















661,585



480,797



















480,797Class C units


40,492



















40,492Class D units


112,454



















112,454Class E units


175,634



















175,634Subordinated units


























10,379



















10,379Paid-in capital


23,773



1



1,507,285



628,375



(2,135,661
)


23,773



10,585



1



524,940



17,445



(542,386
)


10,585Accumulated (deficit) earnings


(7,867
)


(1
)


77,837



4,350



(82,186
)


(7,867
)


2,918



(1
)


181,258



1,933



(183,190
)


2,918Deferred compensation














































Other comprehensive loss


(111,935
)






(111,935
)






111,935



(111,935
)


(32,093
)






(32,093
)






32,093



(32,093
)894,136







1,473,187



632,725



(2,105,912
)


894,136



472,586







674,105



19,378



(693,483
)


472,586Total liabilities and members/partners capital

$
1,539,438


$



$
1,702,832


$
632,725


$
(2,105,912
)

$
1,769,083


$
709,251


$



$
810,786


$
19,378


$
(700,357
)

$
839,058  F-27




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENTS OF OPERATIONS
  For the Year Ended December 31, 2007

For the Year Ended December 31, 2006Investment 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

$



$



$
518,431


$



$



$
518,431


$



$



$
448,054


$



$



$
448,054Natural gas liquids sales










491,432











491,432











369,892











369,892Crude oil sale










77,142











77,142























Transportation, compression and processing fees










22,306











22,306











16,232











16,232Condensate and other










32,349











32,349











26,094











26,094Total revenue










1,141,660











1,141,660











860,272











860,272Costs and expenses:Cost of natural gas and natural gas liquids










853,964











853,964











669,158











669,158Cost of crude oil










73,814











73,814Transportation










6,948











6,948











3,026











3,026Operations and maintenance


1,764







39,392











41,156



917







31,567











32,484Depreciation and amortization


34







39,933











39,967



66







31,927











31,993General and administrative


10,848







23,790











34,638



9,296



1



17,238











26,535Taxes other than income










2,637











2,637











2,061











2,061Equity in earnings from unconsolidated affiliates










(2,850
)


(2,850
)


2,850



(2,850
)










(1,297
)


(1,297
)


1,297



(1,297
)Total costs and expenses


12,646







1,037,628



(2,850
)


2,850



1,050,274



10,279



1



753,680



(1,297
)


1,297



763,960Operating (loss) income


(12,646
)






104,032



2,850



(2,850
)


91,386



(10,279
)


(1
)


106,592



1,297



(1,297
)


96,312Other income (expense):Interest and other income


247







2,607











2,854











1,706











1,706Interest and other financing costs


(29,467
)






116











(29,351
)


(33,207
)






303











(32,904
)(Loss) income before income taxes and equity in earnings from
    consolidated subsidiaries


(41,866
)






106,755



2,850



(2,850
)


64,889



(43,486
)


(1
)


108,601



1,297



(1,297
)


65,114Provision for income taxes


(1,714
)


















(1,714
)






















(Loss) income before income taxes and equity in earnings from
    consolidated subsidiaries


(43,580
)






106,755



2,850



(2,850
)


63,175



(43,486
)


(1
)


108,601



1,297



(1,297
)


65,114Equity in earnings from consolidated subsidiaries


106,755















(106,755
)






108,600















(108,600
)


Net income (loss)

$
63,175


$



$
106,755


$
2,850


$
(109,605
)

$
63,175


$
65,114


$
(1
)

$
108,601


$
1,297


$
(109,897
)

$
65,114  F-28




---



##### 



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, 2005Investment inGuarantor

Non-GuarantorParent

Co-Issuer

Subsidiaries

Subsidiaries

Eliminations

Total(In thousands)Revenue:Natural gas sales

$



$



$
496,906


$



$



$
496,906Natural gas liquids sales










224,695











224,695Transportation, compression and processing fees










15,110











15,110Other










11,032











11,032Total revenue










747,743











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










641,315











641,315Transportation










2,337











2,337Operations and maintenance


66







18,393











18,459Depreciation and amortization


66







16,986











17,052General and administrative


5,486







12,670











18,156Taxes other than income










1,178











1,178Equity in earnings from unconsolidated affiliates










(927
)


(927
)


927



(927
)Total costs and expenses


5,618







691,952



(927
)


927



697,570Operating (loss) income


(5,618
)






55,791



927



(927
)


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


3







1,023







(386
)


640Interest and other financing costs


(16,848
)






(3,999
)






386



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


(22,463
)






52,815



927



(927
)


30,352Equity in earnings from consolidated subsidiaries


52,815















(52,815
)


Net income (loss)

$
30,352


$



$
52,815


$
927


$
(53,742
)

$
30,352  F-29




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 7 
    Long-Term Debt (Continued)
  CONDENSED
    CONSOLIDATING STATEMENTS OF CASH FLOWS
  For the Year Ended December 31, 2007

For the Year Ended December 31, 2006Investment 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

$
(19,109
)

$



$
147,327


$
3,706


$
(3,706
)

$
128,218


$
(55,791
)

$
(1
)

$
147,471


$



$



$
91,679Cash Flows From Investing Activities:Net cash (used in) provided by investing activities


(605,668
)






(727,052
)


(1,051
)


606,719



(727,052
)


61,269







(70,700
)


(10,438
)


(50,422
)


(70,291
)Cash Flows From Financing Activities:Net cash provided by (used in) financing activities


633,509







604,174



1,727



(607,395
)


632,015



(5,359
)






(62,702
)


10,438



50,422



(7,201
)Net increase (decrease) in cash and cash equivalents


8,732







24,449



4,382



(4,382
)


33,181



119



(1
)


14,069











14,187Cash and cash equivalents, beginning of year


1,286







38,198











39,484



1,167



1



24,129











25,297Cash and cash equivalents, end of year

$
10,018


$



$
62,647


$
4,382


$
(4,382
)

$
72,665


$
1,286


$



$
38,198


$



$



$
39,484  F-30




---



##### 



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, 2005Investment inGuarantor

Non-GuarantorParent

Co-Issuer

Subsidiaries

Subsidiaries

Eliminations

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

$
(47,292
)

$



$
47,572


$



$



$
280Cash Flows From Investing Activities:Net cash (used in) provided by investing activities


(500,638
)






(491,708
)


(2,722
)


503,360



(491,708
)Cash Flows From Financing Activities:Net cash provided by (used in) financing activities


548,973



1



461,374



2,722



(503,360
)


509,710Net increase in cash and cash equivalents


1,043



1



17,238











18,282Cash and cash equivalents, beginning of year


124







6,891











7,015Cash and cash equivalents, end of year

$
1,167


$
1


$
24,129


$



$



$
25,297  F-31




---



##### 





COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 7 
    Long-Term Debt (Continued)
  Other
    Indebtedness
      Scheduled
    Maturities of Long-Term Debt
    PrincipalYear

Amount2007

$
2008


2009


2010


2011


Thereafter


630,000$
630,000   Note 8 
    Members
    Capital  Common
    Units
    Form S-3,
   F-32




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)  Form S-3,
    Form S-3/ASR,
      Year Ended December 31,Period Cover

2007


2006


2005January 1, 2005 through September 30, 2005

$



$



$
4,068October 1, 2005 through September 30, 2006






4,607



October 1, 2006 through September 30, 2007


9,965







     Class B
    Units
  Form S-3,
 F-33




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)  Class C
    Units
  12-month, 18-month 24-month
    Form S-3/ASR,
  Class D
    Units
       F-34




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)  Class E
    Units
    Form S-3/ASR,
  Subordinated
    Units
    Form S-3/ASR,
  Distributions
    DistributionQuarter
    Ending(a)

Per Unit


Date Declared


Record Date


Payment Date


AmountDecember 31, 2004

$
0.1000
(a)


January 18, 2005



February 1, 2005



February 14, 2005


$
2,115,000March 31, 2005


0.2100



April 18, 2005



May 2, 2005



May 13, 2005



4,450,000June 30, 2005


0.2250
(b)


July 15, 2005



August 1, 2005



August 15, 2005



7,819,000September 30, 2005


0.2500



October 17, 2005



November 1, 2005



November 14, 2005



8,449,000December 31, 2005


0.2750



January 18, 2006



February 1, 2006



February 14, 2006



10,081,000March 31, 2006


0.3000



April 18, 2006



May 1, 2006



May 15, 2006



11,000,000June 30, 2006


0.3375



July 19, 2006



August 1, 2006



August 14, 2006



12,400,000September 30, 2006


0.3750



October 18, 2006



November 1, 2006



November 14, 2006



13,800,000December 31, 2006


0.4000



January 18, 2007



February 1, 2007



February 14, 2007



17,025,000March 31, 2007


0.4200



April 18, 2007



May 1, 2007



May 15, 2007



17,881,000June 30, 2007


0.4400



July 18, 2007



August 1, 2007



August 14, 2007



18,743,000September 30,
    2007(c)


0.4700



October 17, 2007



November 1, 2007



November 14, 2007



20,276,000December 31, 2007


0.5100



January 16, 2008



February 1, 2008



February 14, 2008



24,336,000  F-35




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)    (a)
    
    The distribution for the quarter ended December 31, 2004
    reflected a pro rata portion of our $0.20 per unit MQD, covering
    the period from the November 15, 2004 closing of our
    initial public offering through December 31, 2004.(b)
    
    Includes a concurrent quarterly distribution of $0.2475 per unit
    with respect to 9,661,516 Class B units issued in
    connection with the closing of the ScissorTail Acquisition.(c)
    
    Common units issued on October 19, 2007 were not eligible
    for this distribution pursuant to the provisions of the Unit
    Purchase Agreement.  Accounting
    for Equity-Based Compensation
  Restricted Common Units,
    Phantom Units Unit Options
  Restricted Common Units.
      2007


2006


2005Weighted





Weighted





WeightedAverage





Average





AverageNumber of


Grant-


Number of


Grant-


Number of


Grant-Restricted


Date Fair


Restricted


Date Fair


Restricted


Date FairUnits


Value


Units


Value


Units


ValueOutstanding at beginning of period


315,936


$
20.84



278,236


$
18.30



36,000


$
12.06Granted


23,500



37.20



120,540



24.51



258,940



18.87Vested


(93,742
)


19.56



(69,306
)


17.38



(12,524
)


12.41Forfeited


(4,513
)


21.09



(13,534
)


19.01



(4,180
)


18.09Outstanding at end of period


241,181


$
22.92



315,936


$
20.84



278,236


$
18.30    F-36




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)      Phantom Units.
      WeightedNumber of


AveragePhantom


Grant-DateUnits


Fair ValueOutstanding at beginning of year





$
Granted


101,465



40.82Vested






Forfeited


(670
)


41.74Outstanding at end of period


100,795


$
40.81     Unit Options.
 F-37




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)      2007


2006


2005Number 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


1,212,506


$
17.15



982,220


$
15.09



400,000


$
10.00Granted


418,200



37.60



315,490



23.52



618,220



18.26Exercised


(115,288
)


15.72



(30,064
)


12.58



(8,880
)


10.00Forfeited


(72,571
)


29.92



(55,140
)


18.01



(27,120
)


13.87Outstanding at end of period


1,442,847


$
22.60



1,212,506


$
17.15



982,220


$
15.09Aggregate intrinsic value at end of period

$
19,843,000






$
15,337,000Weighted average remaining contractual term


8.1 years







8.6 yearsExercisable Options:Outstanding at end of period


362,645


$
15.43



236,268


$
13.81



75,376


$
10.20Aggregate intrinsic value at end of period

$
7,585,000






$
3,779,000Weighted average remaining contractual term


7.5 years







8.2 yearsWeighted average fair value of option granted





$
4.33






$
3.10






$
2.57Options expected to vest:At end of period


1,298,562


$
22.60



1,091,256


$
17.15Aggregate intrinsic value at end of period

$
17,859,000






$
13,803,000Weighted average remaining contractual term


8.1 year







8.6 years       Year Ended December 31,2007


2006


2005Weighted average exercise price

$
37.60


$
23.52


$
18.26Expected volatility


20.6-21.5
%


21.3-22.5
%


24.5-26.9
%Distribution yield


6.00-6.10
%


5.97-6.04
%


6.27-6.51
%Risk-free interest rate


3.48-5.11
%


4.33-5.14
%


3.74-4.59
%Expected term (in years)


6.5



6.5



7Weighted average grant-date fair value of options granted

$
4.33


$
3.10


$
2.57Total intrinsic value of options exercised

$
2,361,000


$
412,000


$
82,000  F-38




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 8 
    Members
    Capital  (Continued)    Note 9 
    Related
    Party Transactions  Operations
    Services
     F-39




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Related
    Party Transactions  (continued)  Natural
    Gas and Related Transactions
    Year Ended December 31,2007


2006


2005Affiliates of Mr. Eckel:Natural gas
    sales(1)

$
31


$
97


$
Gathering and compression
    services(2)


30



32



31Natural gas
    purchases(3)


2,251



1,808



1,495Webb Duval:Natural gas
    sales(1)






706



355Natural gas
    purchases(3)


955



1,695



3,359Transportation
    costs(4)


357



358



475Southern Dome:Natural gas liquid
    sales(5)


302







Condensate
    sales(6)


145







Bighorn:(7)Gathering
    costs(4)


166







Fort Union:(7)Gathering
    costs(4)


2,110Treating
    costs(3)


125







Other:(8)Natural gas
    sales(1)


212







     (1)
    
    Revenues included in natural gas sales on our consolidated
    statements of operations.(2)
    
    Revenues included in transportation, compression and processing
    fees on our consolidated statements of operations.(3)
    
    Included in costs of natural gas and natural gas liquids on our
    consolidated statements of operations.(4)
    
    Costs included in transportation on our consolidated statements
    of operations.(5)
    
    Revenues included in natural gas liquid sales on our
    consolidated statements of operations.(6)
    
    Revenues included in condensate and other on our consolidated
    statements of operations.(7)
    
    For the period from October 1, 2007 through
    December 31, 2007.(8)
    
    For the period from May 1, 2007 through December 31,
    2007.     F-40




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 9 
    Related
    Party Transactions  (continued)          Note 10 
    Customer
    Information    Percentage
    of Consolidated
    Revenue(1)
  Year Ended December 31,Customer

Segment

2007


2006


2005Enterprise Products Operating, L.P.

Texas


20
%


19
%


ONEOK Energy Services, L.P.

Oklahoma


16
%


21
%


ONEOK Hydrocarbon, L.P.

Oklahoma


14
%


13
%


KMTP

Texas


10
%


14
%


26
%Dow Hydrocarbons and Resources Inc.

Texas










12
%   Percentage
    of Consolidated Cost of Goods
    Sold(1)
  Year Ended December 31,Producers

Segment

2007


2006


2005New Dominion LLC

Oklahoma


18
%


19
%


8
%Altex Resources, Inc.

Oklahoma



%


5
%


Noble Energy, Inc.

Texas



%






7
%  F-41




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 10 
    Customer
    Information  (Continued)  Percentage
    of Consolidated Accounts
    Receivable(1)
  Year Ended December 31,Customer

Segment

2007


2006


2005ONEOK Energy Services, L.P.

Oklahoma


18
%


25
%


27
%ONEOK Hydrocarbon, L.P.

Oklahoma


13
%


13
%


Enterprise Products Operating, L.P.

Texas


10
%


11
%


KMTP

Texas


8
%


12
%


23
%CenterPoint Energy, Inc.

Texas










10
%     (1)
    
    Percentages are not provided for periods for which the customer
    or producer is not considered significant.  Note 11 
    Risk
    Management Activities    Commodity
    Risk Hedging Program
       F-42




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 11 
    Risk
    Management Activities  (Continued)      Estimate ofOCI to beRealized Gain (Loss)


Reclassed toFair Value


Ineffectiveness


Year Ended


Earnings inTerm


December 31,


Year Ended December 31,


December 31,


the NextFrom


To


2007


2006


2007


2006


2005


2007


2006


2005


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


Put



September 2005



December 2007


$



$
178


$



$
(40
)

$
(35
)

$
(2,088
)

$
(1,376
)

$
(12
)

$
Natural
    Gas(2)


Put



January 2006



December 2009



3,285



14,118



(18
)


8







4,671



7,553







308Natural Gas
    Liquids(2)


Put



January 2006



December 2008



2



3,714



6



(125
)






(9,173
)


(4,919
)






10,523Natural Gas
    Liquids(2)


Swap



January 2006



December 2008



(16,339
)


(5,187
)


(24
)


(195
)






(6,064
)


448







26,811Natural Gas Call
    Spreads(3)


Put/Call



January 2007



December 2011



8,676



7,589















2,434











703West Texas Intermediate crude
    oil(1)


Put



January 2007



December 2011



625



4,603



53











(123
)










997Natural Gas
    Liquids(2)


Put



January 2007



December 2011



262



7,165



(17
)


(1
)






(1,321
)










2,682West Texas Intermediate crude
    oil(1)


Put



January 2008



December 2011



505







(6
)






















768Natural Gas
    Liquids(2)


Put



January 2008



December 2011



528







(94
)










(909
)










3,636Natural Gas
    Liquids(2)


Swap



January 2007



December 2011



(45,741
)






(117
)










(3,682
)










26,811     (1)
    
    The derivatives are intended to hedge the risk of extreme
    adverse fluctuations of 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)
    
    The derivatives are intended to hedge the risk of extreme
    adverse fluctuations in the prices of the commodities hedged.(3)
    
    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 plant
    against adverse price fluctuations in the underlying price
    indices. The call spread reduces risk to the profitability and
    cash flow of the Houston Central plant.   F-43




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 11 
    Risk
    Management Activities  (Continued)    Interest
    Rate Risk Hedging Program
           F-44




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 11 
    Risk
    Management Activities  (Continued)      Fair Value ofReceived (Paid) During the


Liability atNotional


Fixed


Year Ended December 31,


December 31,Effective Date

Expiration Date


Amount


Rate


2007


2006


2005


2007October 24, 2005


July 31, 2010


$
25,000,000



4.7150
%

$
133,000


$
83,000


$
(26,000
)

$
575,000October 24, 2005


July 31, 2010


$
25,000,000



4.7075
%

$
135,000



85,000



(28,000
)


570,000September 17, 2007


October 9, 2011


$
40,000,000



4.7700
%

$
44,000











1,129,000October 19, 2007


October 18, 2012


$
45,000,000



4.6900
%

$
46,000











1,167,000October 19, 2007


October 18, 2012


$
25,000,000



4.6800
%

$
23,000











643,000     Note 12 
    Fair
    Value of Financial Instruments    December 31,2007


2006Carrying


Estimated


Carrying


EstimatedValue


Fair Value


Value


Fair Value(In thousands)Cash and cash equivalents

$
72,665


$
72,665


$
39,484


$
39,484Credit Facility


280,000



280,000



30,000



30,000Senior Notes


350,773



352,625



225,000



232,875   Note 13 
    Commitments
    and Contingencies  Commitments
  2008 2009 2010 2011 2012
   F-45




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 13 
    Commitments
    and Contingencies  (Continued)        Original


ContingentContingent


NoteYear Ended


Payment due




Note


MaximumDecember 31,


March


Status

Payments


Payments2004



2005


Expired

$
7,500


$
2005



2006


Expired


9,167



2006



2007


Expired


10,833



2007



2008


Rolled to 2008


10,833



2008



2009





11,667



22,500$
50,000


$
22,500      F-46




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 13 
    Commitments
    and Contingencies  (Continued)    Guarantees
  Guarantors Accounting and Disclosure
    Requirements for Guarantees, Including Indirect Guarantees of
    Indebtedness of Others,
  Regulatory
    Compliance
    Litigation
      Note 14 
    Supplemental
    Disclosures to the Statements of Cash Flows  Year Ended December 31,2007

2006

2005Cash payments for interest, net of $932,000, $693,000 and $0
    capitalized in 2007, 2006 and 2005, respectively

$
24,471


$
26,884


$
9,666Cash payments for federal and state income taxes

$



$



$
15  F-47




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 14 
    Supplemental
    Disclosures to the Statements of Cash Flows
    (Continued)    Note 15 
    Segment
    Information    
    Oklahoma, which includes natural gas midstream services in
    central and eastern Oklahoma, including natural gas gathering
    and related compression and dehydration services and natural gas
    processing and a crude oil pipeline. Our Oklahoma segment
    includes assets acquired in the Cimmarron Acquisition and our
    equity investment in Southern Dome.  
    Texas, which performs natural gas gathering and transmission and
    related operations and natural gas processing, treating,
    conditioning and related NGL transportation operations in Texas
    and Louisiana. Our Texas segment includes assets acquired in the
    Cimmarron Acquisition and Cantera Acquisition and our equity
    investment in Webb Duval.
    Rocky Mountains, which performs natural gas gathering and
    related operations in Wyoming. Our Rocky Mountains segment
    consists of assets we acquired through the Cantera Acquisition,
    including our equity investments in Bighorn and Fort Union.     F-48




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
    Note 15 
    Segment
    Information  (Continued)    Rocky


Total


CorporateOklahoma


Texas


Mountains


Segments


and Other


ConsolidatedYear Ended December 31, 2007:Sales to external customers

$
589,371


$
574,353


$
9,181


$
1,172,905


$
(31,245
)

$
1,141,660Intersegment sales


(400
)


400















Interest and other financing costs










103



103



29,248



29,351Depreciation and amortization


25,724



12,749



670



39,143



824



39,967Equity in (earnings) loss from unconsolidated affiliates


(1,400
)


(1,576
)


126



(2,850
)






(2,850
)Net income (loss)


63,758



73,976



(138
)


137,596



(74,421
)


63,175Segment assets


682,850



397,192



686,851



1,766,893



2,190



1,769,083Year Ended December 31, 2006:Sales to external customers

$
411,196


$
447,723


$



$
858,919


$
1,353


$
860,272Interest and other financing costs






2







2



32,902



32,904Depreciation and amortization


23,054



8,452







31,506



487



31,993Equity in earnings from unconsolidated affiliates


(91
)


(1,206
)






(1,297
)






(1,297
)Net income (loss)


50,749



56,098







106,847



(41,733
)


65,114Segment assets


584,956



248,273







833,229



5,829



839,058Year Ended December 31, 2005:Sales to external customers

$
200,426


$
546,957


$



$
747,383


$
360


$
747,743Interest and other financing costs






3,924







3,924



16,537



20,461Depreciation and amortization


9,181



7,731







16,912



140



17,052Equity in loss (earnings) from unconsolidated affiliates


7



(934
)






(927
)






(927
)Net income (loss)


23,610



28,716







52,326



(21,974
)


30,352  F-49




---



##### 



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED FINANCIAL STATEMENTS 
    (Continued)
   Note 16 
    Quarterly
    Financial Data (Unaudited)  Year 2007Quarter EndedMarch 31


June 30(1)


September 30(1)


December 31(1)


Year(In thousands, except per unit information)Revenue

$
210,988


$
281,720


$
293,076


$
355,876


$
1,141,660Operating income


14,179



18,957



26,006



32,244



91,386Net income


8,702



13,308



19,667



21,498



63,175Basic net income per common unit


0.21



0.31



0.46



0.46



1.48Diluted net income per common unit


0.20



0.31



0.44



0.39



1.36Basic net income per subordinated unit


0.21















0.21Diluted net income per subordinated unit


0.21















0.21   Year 2006Quarter EndedMarch 31


June 30(1)


September
    30(1)


December
    31(1)


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


0.20



0.52



0.61



0.44



1.77Diluted net income per common unit


0.20



0.51



0.60



0.43



1.75Basic net income per subordinated unit


0.20



0.52



0.61



0.44



1.77Diluted net income per subordinated unit


0.20



0.52



0.61



0.43



1.76     (1)
    
    Our historical results of operations for the quarters ended
    June 30, 2007, September 30, 2007 and
    December 31, 2007 may not be comparable to the first
    quarter of 2007 or quarters in 2006 as a result of the Cimmarron
    Acquisition in May 2007 and the Cantera Acquisition in October
    2007. F-50




---



##### 



INDEPENDENT
    AUDITORS REPORT           
    F-51




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  BALANCE
    SHEET



December 31,
    2007 ASSETSCurrent assets:Cash and cash equivalents

$
3,660,296Accounts receivable


3,203,418Prepaid expenses


116,957Total current assets


6,980,671Property and equipment, net


97,327,215Other assets


243,138Total assets

$
104,551,024LIABILITIES AND MEMBERS EQUITYCurrent liabilities:Accounts payable:Trade

$
1,431,940Related parties


323,054Accrued liabilities


167,905Total current liabilities


1,922,899Commitments and contingencies (Note 6)Members equity


102,628,125Total liabilities and members equity

$
104,551,024    F-52




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  STATEMENT
    OF OPERATIONS  Period
    From October 1, 2007 through December 31,
    2007
  Gathering fee revenue

$
7,809,074Expenses:Operating expenses


2,605,066General and administrative


81,836Depreciation


994,432Total expenses


3,681,334Operating income


4,127,740Other income:Interest income


24,367Other expense


(309
)Total other income


24,058Net income

$
4,151,798    F-53




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  STATEMENT
    OF CASH FLOWS  Period
    From October 1, 2007  through December 31,
    2007
  Cash flow from operating activities:Net income

$
4,151,798Adjustments to reconcile net income to net cash provided by
    operating activities:Depreciation


994,432Changes in operating assets and liabilities:Accounts receivable


269,988Prepaid expenses and other


53,232Accounts payable


(524,106
)Accrued liabilities


81,150Net cash provided by operating activities


5,026,494Cash flow from investing activities:Capital expenditures


(4,117,405
)Net cash used in investing activities


(4,117,405
)Cash flow from financing activities:Priority distributions to members


(583,932
)Distributions to common members


(4,000,000
)Equity contributions from common members


2,896,501Net cash used in financing activities


(1,687,431
)Net decrease in cash and cash equivalents


(778,342
)Cash and cash equivalents, beginning of period


4,438,638Cash and cash equivalents, end of year

$
3,660,296    F-54




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.STATEMENT OF MEMBERS EQUITY 
    Period From October 1, 2007 through December 31,
    2007
  Common Member InterestsCopanoPipelines/RockyMountains, LLC(formerly





CrestoneCantera Gas


Crestone Energy


GatheringHoldings, L.L.C.)


Ventures, L.L.C.


Services, L.L.C.


TotalBalance at October 1, 2007

$
51,083,517


$
39,063,861


$
10,016,380


$
100,163,758Contributions


2,814,057



65,618



16,826



2,896,501Allocation of 2007 contributions


(1,336,841
)


1,064,016



272,825



Distributions


(2,623,932
)


(1,560,000
)


(400,000
)


(4,583,932
)Net income


2,403,543



1,391,469



356,786



4,151,798Balance at December 31, 2007

$
52,340,344


$
40,024,964


$
10,262,817


$
102,628,125    F-55




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS
  Note 1 
    Organization
    and Business    Copano Pipelines/Rocky Mountains, LLC (Copano)
    (formerly Cantera Gas Holdings, L.L.C.), a subsidiary of Copano
    Natural Gas/Rocky Mountains, LLC (formerly Cantera Natural Gas,
    L.L.C.)


51
%Crestone Energy Ventures, L.L.C. (Crestone Energy)


39Crestone Gathering Services, L.L.C. (Crestone
    Gathering)


10100
%           Note 2 
    Summary
    of Significant Accounting Policies  Use of
    Estimates
    Gas
    Gathering Operations
   F-56




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Cash
    and Cash Equivalents
    Imbalances
    Property
    and Equipment
    Useful LivesVehicles


3 years


$
922,866Computer and communication equipment


5 years



511,341Pipeline materials


N/A



26,243Gathering lines and related equipment


30 years



120,550,468122,010,918Less accumulated depreciation






(24,683,703
)Property and equipment, net





$
97,327,215   Asset
    Impairment
    Fair
    Value of Financial Instruments
   F-57




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)  Concentration
    of Credit Risk
        Income
    Taxes
    Accounting for Uncertainty in
    Income Taxes  an Interpretation of FASB Statement
    No. 109.
  Note 3 
    New
    Accounting Pronouncements  Fair
    Value Measurements
  Fair Value Measurements. Accounting for Derivative Instruments and Hedging
    Activities,
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
 F-58




---



##### 



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO
    FINANCIAL STATEMENTS  (Continued)
   Note 3 
    New
    Accounting Pronouncements (Continued)  Business
    Combinations
  Business Combinations
  Note 4 
    Operating
    Leases    Year Ending December 31,2008

$
995,5422009


436,9442010


38,962$
1,471,448     Note 5 
    Related-Party
    Transactions        Note 6 
    Commitments
    and Contingencies   F-59