##### Table of Contents





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, 2008ORo

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. o
  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 14, 2009

Part III




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##### 





TABLE OF
    CONTENTS
   
 PagePART IItem 1.


Business


1Item 1A.


Risk Factors


26Item 1B.


Unresolved Staff Comments


43Item 2.


Properties


43Item 3.


Legal Proceedings


44Item 4.


Submission of Matters to a Vote of Security
    Holders


44PART IIItem 5.


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


45Item 6.


Selected Financial Data


48Item 7.


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


49Item 7A.


Quantitative and Qualitative Disclosures about
    Market Risk


76Item 8.


Financial Statements and Supplementary Data


83Item 9.


Changes in and Disagreements with Accountants on
    Accounting and Financial Disclosure


83Item 9A.


Controls and Procedures


83Item 9B.


Other Information


86PART IIIItem 10.


Directors and Executive Officers of the
    Registrant


87Item 11.


Executive Compensation


87Item 12.


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


87Item 13.


Certain Relationships and Related Parties


87Item 14.


Principal Accountant Fees and Services


87PART IVItem 15.


Exhibits and Financial Statement Schedules


88FINANCIAL STATEMENTSCopano Energy, L.L.C. Index to Financial
    Statements


F-1EX-10.15EX-23.1EX-31.1EX-31.2EX-32.1EX-32.2




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##### Table of Contents



PART I      /d:

Per day$/gal:

U.S. dollars per gallonBbls:

BarrelsBcf:

One billion cubic feetBtu:

One British thermal unitGPM:

Gallons per minuteMMBtu:

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 products 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 pipeline 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
  59-mile
    Recent
    Developments
  Declaration of Distribution.
 1




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Saint Jo Processing Plant.
  McMullen Lateral Acquisition. No. CP09-38) 151-mile, 24-inch
  Other Expansion Projects. 6-inch
    Unit Conversions.
  Repurchase and Retirement of Senior
    Notes.
  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 2




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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 supplement our
    operations through complementary acquisitions of midstream
    assets in our operating areas. We pursue acquisitions that we
    believe will allow us to capitalize on our existing
    infrastructure, personnel, and producer and customer
    relationships to increase capacity utilization and 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 margins and 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.    
    Developing and exploiting flexibility in our
    operations.  When appropriate, 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 modes of operation, 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.When appropriate,
    we pursue potential acquisitions in new regions where we believe
    growth opportunities are attractive and our business strategies
    could be applied. For example, in October 2007, we expanded into
    the Rocky Mountains region with the Cantera acquisition, and in
    August 2005, we expanded into Oklahoma with the acquisition of
    ScissorTail Energy.  Our
    Operations
   3




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Our
    Operating Segments
  Overview
    Copano
    Energy Operating Segments
  Year EndedDecember 31, 2008Pipeline
    Miles(1)





Average/Number of


Throughput


ThroughputProcessing


/Inlet


/Inlet


UtilizationSegment

Assets

Plants


Capacity(2)(3)


Volumes(2)(3)


of CapacityOklahoma

Natural Gas Pipelines


3,658



301,100



200,687



67
%Processing
    Plants(4)(5)


4



158,000



102,079



65
%Crude Oil
    Pipeline(6)


59



3,960



3,960



100
%Texas

Natural Gas
    Pipelines(7)


1,994



975,800



370,332



38
%Processing
    Plants(8)


3



930,000



562,573



60
%NGL
    Pipelines(9)


200



68,150



15,248



22
%Rocky Mountains

Natural Gas
    Pipelines(10)


569



1,550,000



986,054



64
%     (1)
    
    Natural gas pipeline miles for
    Oklahoma and Texas exclude 2,973 miles and 627 miles,
    respectively, of inactive pipelines that are being held for
    potential future development.(2)
    
    Pipeline capacity values generally
    are based on current operating configurations and could be
    increased through additional compression, increased delivery
    meter capacity or other facility upgrades.(3)
    
    Natural gas pipeline throughputs
    and inlet capacity are presented in Mcf/d. Crude oil and NGL
    pipeline throughputs and capacity are presented in Bbls/d.(4)
    
    Includes the Southern Dome plant
    owned by Southern Dome, LLC (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 five third-party plants in exchange for a portion
    of the revenues from the NGLs and residue gas. Average daily
    throughput volumes processed at third-party plants for our
    Oklahoma segment were 43,117 Mcf/d for the year ended
    December 31, 2008.(6)
    
    Average throughput of the crude oil
    pipeline excludes 842 Bbls/d of crude delivered to third
    parties via transport trucks.(7)
    
    Includes the
    144-mile
    Webb/Duval system owned by Webb/Duval Gatherers (Webb
    Duval), an unconsolidated partnership in which we own a
    62.5% interest.(8)
    
    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.(9)
    
    Includes our
    46-mile
    Brenham NGL pipeline, which we lease from Kinder Morgan Texas
    Pipeline and placed into service in March 2008, and our Markham
    NGL pipeline, which will be placed into service in the second
    half of 2009.(10)
    
    Owned by Bighorn and
    Fort Union, in which we own 51.0% and 37.04% interests,
    respectively. We do not operate Fort Union.  Oklahoma
    
    nine primarily low-pressure gathering systems occupying
    approximately 53,000 square miles;
    four processing plants, one of which we own through our majority
    interest in Southern Dome; and
    a crude oil pipeline. 4




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5




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Oklahoma
    Pipelines
  Diameter of





Year Ended December 31, 2008Length


Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


of CapacityNatural Gas Pipelines:Stroud


821



22-
    162



124,000



101,503



82
%Milfay


356



22-
    162



15,000



14,050



94
%Glenpool


1,016



22-
    102



19,000



10,290



54
%Twin Rivers


540



22-
    122



23,000



11,771



51
%Central
    Oklahoma(3)


210



32-
    102



4,100



3,361



82
%Osage


549



22- 82



26,000



19,649



76
%Mountain(4)


166



22-
    202



90,000



40,063



45
%Crude Oil
    Pipeline(5)


59



42-
    62



3,960



3,960



100
%     (1)
    
    Capacity values generally 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 presented in Mcf/d. Crude oil throughputs are presented in
    Bbls/d.(3)
    
    Excludes 2,973 miles of
    inactive pipelines held for potential future development.(4)
    
    The Mountain system consists of
    three systems: Blue Mountain, Cyclone Mountain and Pine Mountain.(5)
    
    Average throughput of the crude oil
    pipeline excludes 842 Bbls/d of crude delivered to third
    parties via transport trucks.  Oklahoma
    Processing
  Year Ended December 31, 2008Average


Utilization


Average ProcessingThroughput


Inlet


of


Volumes(1)Processing Plants

Facilities

Capacity(1)


Volumes(1)


Capacity


NGLs


ResiduePaden

Cryogenic/refrigeration


100,000



74,079



74
%


10,402



59,270Ethane rejection Nitrogen rejection(3)Milfay

Propane refrigeration


15,000



9,841



66
%


679



8,816Glenpool

Cryogenic


25,000



9,719



39
%


489



9,187Southern
    Dome(2)

Propane refrigeration


18,000



8,440



47
%


356



7,909     (1)
    
    Throughput capacity and inlet
    volumes are measured in Mcf/d. NGL volumes are presented in
    Bbls/d. Residue volumes are presented in MMBtu/d.(2)
    
    We own 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.(3)
    
    The nitrogen rejection unit removes
    entrained nitrogen from the natural gas stream associated with
    the cryogenic portion of the Paden plant, which has capacity of
    60,000 Mcf/d.   6




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##### Table of Contents



Stroud
    System and Interconnected Area
  Stroud System.
  Paden Processing Plant.
      Milfay System and Processing Plant.
  Glenpool System and Processing Plant.
  Twin Rivers System.
  Central Oklahoma System.
  Osage
    System
    Mountain
    Systems
   7




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Crude Oil
    Pipeline
    Southern
    Dome
      Texas
   8




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9




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Texas
    Pipelines
  Year EndedDecember 31, 2008Length


Diameter of Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


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


1,119



22-
    202



562,800



184,827



33
%Houston Central


328



22-
    122



239,000



127,341



53
%Upper Gulf Coast


239



22-
    122



139,000



32,041



23
%North
    Texas(5)


308



32-
    122



35,000



26,123



75
%NGL Pipelines:Sheridan NGL
    Pipeline(6)


104



62



27,900



9,943



36
%Brenham NGL
    Pipeline(7)


46



62



20,250



5,304



26
%Markham NGL
    Pipeline(8)


50



62



20,000







     (1)
    
    Capacity values generally 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 presented in Mcf/d. NGL throughputs are presented 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 627 miles of inactive
    pipelines held for potential future development.(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)
    
    The Brenham NGL pipeline was placed
    into service in March 2008.(8)
    
    We acquired the
    50-mile
    Markham NGL pipeline from Dow Hydrocarbons and Resources LLC in
    December 2008. We expect to place the pipeline into purity
    ethane service in the second half of 2009.  Texas
    Processing
  Year Ended December 31, 2008Average





Average ProcessingThroughput

Inlet


Utilization of


Volumes(1)Processing Plants

Facilities

Capacity(1)

Volumes(1)


Capacity


NGLs


ResidueHouston Central

Cryogenic/lean oil

700,000


542,704



78
%


14,148
(2)


513,568Ethane rejectionSaint
    Jo(3)

Refrigeration

30,000


15,218



51
%


427



14,930Lake Charles

Cryogenic

200,000


4,651
(4)


2
%


141
(4)


4,529
(4)     (1)
    
    Throughput capacity and inlet
    volumes are presented in Mcf/d. NGL volumes are presented in
    Bbls/d. Residue volumes are presented in MMBtu/d.(2)
    
    NGL volumes from the Houston
    Central plant includes average daily volumes of
    6,577 Bbls/d and 5,304 Bbls/d of ethane, propane,
    butane and natural gasoline mix delivered to the Sheridan and
    Brenham NGL pipelines, respectively, and 2,264 Bbls/d of
    stabilized condensate delivered to the TEPPCO crude oil pipeline.(3)
    
    We are leasing a 30,000 Mcf/d
    refrigeration plant during construction of a permanent
    100,000 Mcf/d cryogenic processing plant. Upon completion
    in the second quarter of 2009, the cryogenic plant will
    initially be configured for 50,000 Mcf/d.(4)
    
    Average inlet volumes and average
    processing volumes for the Lake Charles plant represent fourteen
    days of activity in 2008. 10




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South
    Texas
  South Texas Systems. 30-inch
        Houston Central Systems and Processing
    Plant.
    
    8,029 horsepower of inlet compression;
    8,400 horsepower of tailgate compression;
    a 1,200 GPM 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.      163-acre
  Sheridan, Brenham and Markham NGL
    Pipelines.
  5-year
    Our Commercial Relationship With KMTP. 30-inch-diameter
  Upper
    Gulf Coast Systems
   12




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##### Table of Contents



North
    Texas Systems
  18-mile, 12-mile, 10-inch 5-mile, 6-inch
  Rocky
    Mountains
    Rocky
    Mountains Pipelines and
    Services(1)
  Diameter of





Year Ended December 31, 2008Length


Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(3)


Throughput(2)(3)


of CapacityNatural Gas Pipelines:Bighorn


251



62-
    242



300,000



219,958



73
%Fort Union(5)


318



242



1,250,000



766,096



61
%Producer
    Services(4)














227,424



     (1)
    
    Includes Bighorn, in which we own a
    51.0% managing member interest, and Fort Union, in which we
    own a 37.04% managing member interest.(2)
    
    Capacity values generally are based
    on current operating configurations and could be increased
    through additional compression, increased delivery meter
    capacity or other facility upgrades.(3)
    
    Natural gas pipeline throughputs
    are presented in Mcf/d.(4)
    
    Producer Services volumes consist
    of volumes we purchased for resale, volumes gathered under our
    firm capacity gathering agreements with Fort Union and
    volumes transported using our firm capacity agreements with WIC.
    Currently we have 430,102 Mcf/d of firm capacity on
    Fort Union, 223,150 Mcf/d of which currently is demand
    capacity, and 246,100 MMBtu/d of firm capacity on
    WICs Medicine Bow lateral pipeline. Through capacity
    release agreements with producers in the Powder River Basin, we
    have sold, or released, 92% of our WIC capacity.(5)
    
    Fort Union also has a 900 GPM
    amine treating facility at Medicine Bow, Wyoming. Upon
    completion of the second phase of an ongoing expansion in the
    first quarter of 2009, the treating facility will have capacity
    of 1,500 GPM. 13




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14




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##### Table of Contents



Bighorn
    Gathering System
      Fort Union
    Gathering System
    demand capacity variable capacity)
      Producer
    Services
   15




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Natural
    Gas Supply
        Oklahoma
      Texas
   16




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##### Table of Contents



Rocky
    Mountains
      3.8 million-acre AMI
    Competition
      Oklahoma
        Texas
   17




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##### Table of Contents



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 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 18




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##### Table of Contents



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.
    Stabilized condensate is primarily used as a refinery feedstock
    for the production of motor gasoline and other products. 19




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
    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 used 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
    Industry
    Regulation
  FERC Regulation of Intrastate Natural Gas
    Pipelines.
  and/or
   20




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##### Table of Contents



FERC Regulation of NGL Pipelines.
  FERC Regulation of Crude Oil Pipelines. No. OR08-14)
  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.        Hazardous Waste.
 22




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Site Remediation.
    Air Emissions.
  Water Discharges.
 23




---



##### Table of Contents



Pipeline Safety.
    Employee Health and Safety.
  Anti-terrorism Measures.
  Climate Change.
 24




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##### Table of Contents



e.g. e.g
  Massachusetts, et
    al. v. EPA Massachusetts Massachusetts
  Office
    Facilities
    Employees
  Page F-1
  Available
    Information
  1-800-SEC-0330. (http://www.sec.gov)
  (http://www.copanoenergy.com) (713-621-9547) Form 10-K,
 25




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Form 10-Q, Form 8-K
  Item 1A.
    Risk
    Factors  In addition to the factors discussed elsewhere in this
    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 that may adversely affect our
    business. Additional risks and uncertainties not presently known
    to us or that we currently deem immaterial also may impair our
    business operations and financial condition. If any of these
    risks or uncertainties were to occur, our business, financial
    condition or results of operation could be adversely
    affected.
  Risks
    Related to Our Business
  We may
    not have sufficient cash after establishment of cash reserves to
    pay cash distributions at the current level.
    
    the amount of natural gas gathered and transported on our
    pipelines;
    the amount and NGL content of the natural gas we process;
    the fees we charge and the margins we realize for our services:
    the prices 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; and
    the weather in our operating areas.    
    the level of capital expenditures we make and the profitability
    of those projects;
    our ability to access capital markets and borrow money;
    the cost of acquisitions, if any;
    the effectiveness of our hedging program and the
    creditworthiness of our hedging counterparties;
    our debt service requirements;
    fluctuations in our working capital needs;
    restrictions on distributions imposed by our revolving credit
    facility and the indentures governing our senior unsecured notes;
    any restrictions on distributions by entities in which we own
    interests;
    the amount of cash reserves established by our Board of
    Directors for the proper conduct of our business; and
    prevailing economic conditions.   26




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##### Table of Contents



A
    decrease in our cash flow will reduce the amount of cash we have
    available for distribution to our unitholders.
    To the
    extent that we make acquisitions in the future and our
    acquisitions do not perform as expected, our future financial
    performance may be negatively impacted.
      
    operating a significantly larger combined organization and
    adding operations;
    difficulties in the assimilation of the assets and operations of
    the acquired businesses, especially if the assets acquired are
    in a new business segment or geographic area;
    the risk that natural gas reserves expected to support the
    acquired assets may not be of the anticipated magnitude or may
    not be developed as anticipated;
    the loss of significant producers or markets or key employees
    from the acquired businesses;
    the diversion of managements attention from other business
    concerns;
    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;
    coordinating or consolidating corporate, information technology
    and administrative functions; and
    a decrease in liquidity as a result of using significant amounts
    of available cash or borrowing capacity to finance an
    acquisition.    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.
      
    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 disadvantage relative 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.      Due to
    current economic conditions, our ability to obtain funding under
    our revolving credit facility could be impaired.
      
    one or more of our lenders may be unable or otherwise fail to
    meet its funding obligations;
    each time we draw on our revolving credit facility, if any of
    the representations or warranties or certain covenants included
    in the agreement are false in any material respect, the lenders
    may refuse to provide funding; and
    if any lender refuses to fund its commitment for any reason,
    whether or not valid, the other lenders are not required to
    provide additional funding to make up for the unfunded portion.   29




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Because
    of the recent deterioration of the credit and capital markets,
    we may be unable to obtain financing from sources other than our
    revolving credit facility on acceptable terms or at
    all.
        We are
    exposed to the credit risk of our customers and other
    counterparties, and a general increase in the nonpayment and
    nonperformance by counterparties could have an adverse impact on
    our cash flows, results of operations and financial
    condition.
    Our
    cash flow and profitability depend upon prices and market demand
    for natural gas and NGLs, which are beyond our control and have
    been volatile.
     30




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##### Table of Contents




    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, LNG 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 for natural gas and NGLs;
    the availability of downstream NGL fractionation facilities;
    the availability and marketing of competitive fuels;
    the impact of energy conservation efforts; and
    the extent of governmental regulation and taxation.    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.
      
    hedging can be expensive, particularly during periods of
    volatile prices;
    our counterparty in the hedging transaction may default on its
    obligation to pay; and 31




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##### Table of Contents




    available hedges may not correspond directly with the risks
    against which we seek protection. For example:  
    the duration of a hedge may not match the duration of the risk
    against which we seek protection;
    variations in the index we use to price a commodity hedge may
    not adequately correlate with variations in the index we use to
    sell the physical commodity (known as basis risk); and
    we may not produce or process sufficient volumes to cover swap
    arrangements we enter into for a given period. If our actual
    volumes are lower than the volumes we estimated when entering
    into a swap for the period, we might be forced to satisfy all or
    a portion of our derivative obligation without the benefit of
    cash flow from our sale or purchase of the underlying physical
    commodity, which could adversely affect our liquidity.    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.
         32




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We
    rely on third-party pipelines and other facilities in providing
    service to our customers. If one or more of these pipelines or
    facilities 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.
   33




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##### Table of Contents



Federal,
    state or local regulatory measures could adversely affect our
    business.
            and/or
 34




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##### Table of Contents



Montana v.
    Wyoming
      A
    change in the characterization of some of our assets by federal,
    state or local regulatory agencies could adversely affect our
    business.
     35




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##### Table of Contents



and/or
    We may
    incur significant costs and liabilities resulting from pipeline
    integrity programs and related repairs.
       36




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##### Table of Contents



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 waste 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.
   37




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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.
   38




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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.      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.
   39




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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.
    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
  
    394,853 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    Increases
    in interest rates could adversely affect our unit
    price.
   40




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##### Table of Contents



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.
          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.
   41




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You
    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
    non-U.S.
    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,
  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.
    We
    prorate our items of income, gain, loss and deduction between
    transferors and transferees of our units each month based upon
    the ownership of our units on the first day of each month,
    instead of on the basis of the date a particular unit is
    transferred. The IRS may challenge this treatment, which could
    change the allocation of items of income, gain, loss and
    deduction among our unitholders.
   42




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A
    unitholder whose units are loaned to a short seller
    to cover a short sale of units may be considered as having
    disposed of those units. If so, he would no longer be treated
    for tax purposes as a partner with respect to those units during
    the period of the loan and may recognize gain or loss from the
    disposition.
    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   43




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##### Table of Contents



Item 3.
    Legal
    Proceedings        Item 4.
    Submission
    of Matters to a Vote of Security Holders   44




---



##### Table of Contents



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


CashCommon Units


DistributionHigh


Low


per Common Unit2008:Quarter Ended December 31

$
24.99


$
8.80


$
0.5750Quarter Ended September 30

$
34.21


$
22.25


$
0.5700Quarter Ended June 30

$
39.75


$
33.00


$
0.5600Quarter Ended March 31

$
37.44


$
31.29


$
0.53002007:Quarter Ended December 31

$
39.75


$
33.53


$
0.5100Quarter Ended September 30

$
44.81


$
33.25


$
0.4700Quarter Ended June 30

$
45.03


$
33.92


$
0.4400Quarter Ended March
    31(1)

$
35.10


$
28.85


$
0.4200     (1)
    
    Prices are adjusted to reflect the March 30, 2007
    two-for-one split of our common units.        Class C
    Units
   45




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##### Table of Contents



Class D
    Units
    Class E
    Units
    Common
    Unitholder Return Performance Presentation
   46




---



##### Table of Contents



Cumulative
    Total Unitholder Return
  
  November 9,


December 31,2004


2004


2005


2006


2007


2008Copano (CPNO)

$
100


$
126


$
180


$
288


$
367


$
127Alerian MLP Total Return Index (AMZX)

$
100


$
106


$
113


$
142


$
160


$
101S&P 500 Index (SPX)

$
100


$
104


$
107


$
122


$
126


$
78     Issuer
    Purchases of Equity Securities
    Recent
    Sales of Unregistered Securities
   47




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Item 6.
    Selected
    Financial Data  Selected
    Historical Consolidated Financial Information
    Year Ended December 31,2008


2007(1)


2006


2005(2)


2004(In thousands, except per unit data)Summary of Operating Results:Revenues

$
1,629,086


$
1,141,660


$
860,272


$
747,743


$
437,656Net income (loss)

$
58,213


$
63,175


$
65,114


$
30,352


$
(915
)Basic net income (loss) per common
    unit(3)

$
1.20


$
1.48


$
1.77


$
1.20


$
(0.17
)Diluted net income (loss) per common
    unit(3)

$
1.01


$
1.36


$
1.75


$
1.15


$
(0.17
)Other Financial Information:Cash distributions per common
    unit(4)

$
2.17


$
1.73


$
1.29


$
0.79


$
0.51   As of December 31,2008


2007(1)


2006


2005(2)


2004Balance Sheet Information:Total assets

$
2,013,665


$
1,769,083


$
839,058


$
792,750


$
178,399Long-term debt


821,119



630,773



255,000



398,000



57,000Members capital


1,037,958



894,136



472,586



281,803



82,356     (1)
    
    Our summary financial information as of and for the year ended
    December 31, 2007 includes results attributable to our
    Cimmarron acquisition from May 1, 2007 through
    December 31, 2007 and our Rocky Mountains segment from
    October 1, 2007 (the date we acquired Cantera) through
    December 31, 2007.(2)
    
    Our summary financial 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
    excludes incremental units related to warrants previously held
    by preferred unitholders and employee unit options because these
    equity securities had an anti-dilutive effect as a result of
    loss reported by us for the period.(4)
    
    Cash distributions for 2004 relate to the distributions paid to
    the pre-IPO unitholders prior to our IPO and are based on
    equivalent units. 48




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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 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 report. In addition, you should review
     Forward-Looking Statements included in
    this Item 7 and Risk Factors included in
    Item 1A of this report for information regarding
    forward-looking statements made in this discussion and certain
    risks inherent in our business, as well as Item 7A,
    Quantitative and Qualitative Disclosures about Market
    Risk.
  Overview
      
    Our Oklahoma segment provides midstream natural gas services in
    central and east Oklahoma, including gathering and related
    compression, dehydration, treating and nitrogen rejection
    services and natural gas processing. This segment also includes
    a crude oil pipeline located in south Oklahoma and north Texas.
    For the years ended December 31, 2008 and 2007, this
    segment generated approximately 53% and 56%, respectively, of
    our total segment gross margin, which is defined below under
     How We Evaluate Our Operations.
    Our Texas segment provides midstream natural gas services in
    south and north 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, Brenham NGL pipeline and,
    beginning in the second half of 2009, the Markham NGL pipeline.
    In addition, we are constructing a treating and processing plant
    in Montague County, Texas, and our Texas segment owns a
    processing plant located in southwest Louisiana. For the years
    ended December 31, 2008 and 2007, this segment generated
    approximately 56% and 58%, 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 with our acquisition of Cantera in
    October 2007. For the years ended December 31, 2008 and
    2007, this segment generated approximately 2% and 1%,
    respectively, of our total segment gross margin. The gross
    margin generated by this segment is derived from the services we
    provide to our Rocky Mountains producers and does not include
    results associated with our interests in Bighorn or
    Fort Union, which are reported as equity in earnings from
    unconsolidated affiliates.    Trends
    and Uncertainties
   49




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Market
    and Industry Trends
  Credit and Capital Market
    Disruptions.
  Commodity Prices and Producer Activity.
    Average
    Daily Prices for Natural Gas and
    NGLs(1)(2)
  
   (1)  Year Ended December 31,



Quarterly Data for 20082006


2007


2008



Q1 2008


Q2 2008


Q3 2008


Q4 2008OklahomaIndices:CenterPoint East ($/MMbtu)

$
6.15


$
6.07


$
7.11



$
7.20


$
9.26


$
8.41


$
3.58Conway ($/barrel)

$
38.61


$
45.93


$
51.28



$
56.33


$
62.27


$
59.42


$
27.36Service Throughput (MMBtu/d)


177,368



199,906



238,836




222,006



228,941



243,000



261,107Segment Gross Margin

$
95,614


$
115,099


$
136,378



$
36,570


$
47,852


$
33,536


$
18,420TexasIndices:Houston Ship Channel ($/MMbtu)

$
6.53


$
6.58


$
8.67



$
7.73


$
10.58


$
9.98


$
6.37Mt. Belvieu ($/barrel)

$
40.27


$
47.58


$
57.24



$
61.01


$
67.81


$
67.54


$
30.06Service Throughput (MMBtu/d)


573,141



642,528



686,791




696,658



700,545



666,686



679,142Segment Gross Margin

$
91,121


$
121,935


$
142,723



$
41,576


$
40,499


$
41,392


$
19,256  50




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##### Table of Contents



(2)
    
    Average prices indicated for Conway and Mt. Belvieu are based on
    our year-to-date average product production mix at the end of
    the period indicated. We operated the Houston Central plant in
    conditioning or ethane-rejection mode for 58 days in the
    fourth quarter, which resulted in a higher average daily price
    on Mt. Belvieu than we would have received for product mix
    extracted in full processing mode. The fourth quarter price
    assuming fully processed average product production mix would
    have averaged $29.58.          Factors
    Affecting 2008 Operating Results and Financial
    Condition
     51




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How We
    Evaluate Our Operations
    Throughput Volumes.
  service throughput
  
    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.    producer services
    throughput
  Segment Gross Margin and Total Segment Gross
    Margin.
   52




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Operations and Maintenance Expenses.
  General and Administrative Expenses.
  EBITDA and Adjusted EBITDA.
 53




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
    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 and Total Distributable Cash
    Flow.
       54




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Non-GAAP Financial Measures.
  Year Ended December 31,2008


2007


2006(In thousands)Reconciliation of total segment gross margin to operating income:Operating income

$
107,994


$
91,386


$
96,312Add:Operations and maintenance expenses


54,561



41,156



32,484Depreciation, amortization and impairment


53,154



39,967



31,993General and administrative expenses


45,571



34,638



26,535Taxes other than income


3,019



2,637



2,061Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Total segment gross margin

$
257,410


$
206,934


$
188,088Reconciliation of EBITDA and adjusted EBITDA to net income:Net income

$
58,213


$
63,175


$
65,114Add:Depreciation, amortization and impairment


53,154



39,967



31,993Interest and other financing costs


64,978



29,351



32,904Provision for income taxes


1,249



1,714



EBITDA

$
177,594


$
134,207


$
130,011Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


19,116



4,589



(14
)Copanos share of depreciation and amortization included in
    equity in earnings from unconsolidated affiliates


5,863



1,830



810Copanos share of interest and other financing costs
    incurred by our equity method investments


3,259



444



Adjusted EBITDA

$
205,832


$
141,070


$
130,807Reconciliation of EBITDA and adjusted EBITDA to cash flows from
    operating activities:Cash flow provided by operating activities

$
89,924


$
128,218


$
91,679Add:Cash paid for interest and other financing costs


60,510



27,685



28,442Equity in earnings from unconsolidated affiliates


6,889



2,850



1,297Distributions from unconsolidated affiliates


(22,460
)


(3,706
)


Risk management activities


27,037



5,201



22,585Decrease (increase) in working capital and other


15,694



(26,041
)


(13,992
)EBITDA


177,594


$
134,207


$
130,011Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


19,116



4,589



(14
)Copanos share of depreciation and amortization included in
    equity in earnings loss from unconsolidated affiliates


5,863



1,830



810Copanos share of interest and other financing costs
    incurred by our equity method investments


3,259



444



Adjusted EBITDA

$
205,832


$
141,070


$
130,807 55




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##### Table of Contents



Year Ended December 31,2008


2007


2006(In thousands)Reconciliation of net income to distributable cash flow:Net income

$
58,213


$
63,175


$
65,114Add: Depreciation, amortization and impairment


53,154



39,967



31,993Amortization of debt issue costs


4,467



1,666



4,462Equity-based compensation


7,789



3,223



1,910G&A reimbursement from pre-IPO unitholders






12,414



4,880Distributions from unconsolidated affiliates


25,830



8,710



Unrealized losses/(gains) associated with line fill
    contributions and gas
    imbalances(1)


592



(12
)


Unrealized losses on derivatives


12,751



10,248



183Deferred taxes and other


1,927



1,096



177Less: Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Maintenance capital expenditures


(11,769
)


(9,062
)


(8,984
)Distributable cash
    flow(1)

$
146,065


$
128,575


$
98,438Add: Amortization of commodity derivative options


32,842



21,045



10,357Total distributable cash
    flow(1)

$
178,907


$
149,620


$
108,795     (1)
    
    Beginning with the third quarter of 2008, unrealized non-cash
    losses (gains) associated with line fill contributions and gas
    imbalances have been added back in the determination of
    distributable cash flow. Prior periods have been adjusted to
    reflect this change.  How We
    Manage Our Operations
    Economic Models and Standardized Processing
    Margin.
    Flow and Transaction Monitoring Systems.
 56




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##### Table of Contents



Producer Activity Evaluation and Reporting.
  Imbalance Monitoring and Control.
  Our
    Contracts
      agreed-upon
  Fee-Based Arrangements.
  Percentage-of-Proceeds Arrangements.
 57




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##### Table of Contents



Percentage-of-Index Arrangements.
  Keep-Whole with Fee Arrangements.
  Our Contracts with Kinder Morgan Texas
    Pipeline. 30-inch-diameter
      Our
    Long-Term Growth Strategy
   58




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##### Table of Contents



Acquisition Analysis.
  Capital Expenditure Analysis.
  Items Impacting
    Comparability of Our Financial Results
  Our
    Acquisitions
   59




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##### Table of Contents



Our
    Results of Operation
  Year Ended December 31,2008


2007


2006($ in thousands)Total segment gross
    margin(1)

$
257,410


$
206,934


$
188,088Operations and maintenance expenses


54,561



41,156



32,484Depreciation, amortization and impairment


53,154



39,967



31,993General and administrative expenses


45,571



34,638



26,535Taxes other than income


3,019



2,637



2,061Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Operating income


107,994



91,386



96,312Gain on retirement of unsecured debt


15,272







Interest and other financing costs, net


(63,804
)


(26,497
)


(31,198
)Provision for income taxes


(1,249
)


(1,714
)


Net income

$
58,213


$
63,175


$
65,114Total segment gross margin:Oklahoma

$
136,378


$
115,099


$
95,614Texas


142,723



121,935



91,121Rocky Mountains


5,877



1,145



Segment gross margin


284,978



238,179



186,735Corporate and
    other(2)


(27,568
)


(31,245
)


1,353Total segment gross
    margin(1)

$
257,410


$
206,934


$
188,088Segment gross margin per unit:Oklahoma:Service throughput
    ($/MMBtu)(3)

$
1.56


$
1.58


$
1.48Texas:Service throughput ($/MMBtu)

$
0.57


$
0.52


$
0.44Rocky Mountains:Producer service throughput
    ($/MMBtu)(4)

$
0.06


$
0.06



Volumes:Oklahoma:(3)(5)Service throughput (MMBtu/d)


238,836



199,906



177,368Plant inlet volumes (MMBtu/d)


156,057



144,050



125,364NGLs produced (Bbls/d)


15,126



13,771



11,811Crude oil service volume (Bbls/d)


4,802



2,417



Texas:(6)(7)Service throughput (MMBtu/d)


686,791



642,528



573,141Pipeline throughput (MMBtu/d)


314,252



296,288



254,886Plant inlet volumes (MMBtu/d)


610,249



567,073



522,465NGLs produced (Bbls/d)


16,150



18,275



14,740Rocky Mountains:Producer service throughput
    (MMBtu/d)(4)


220,792



224,525



Maintenance capital expenditures

$
11,769


$
9,062


$
8,984Expansion capital expenditures


169,056



884,290



53,298Total capital expenditures

$
180,825


$
893,352


$
62,282Operations and maintenance expenses:Oklahoma

$
24,611


$
20,711


$
17,185Texas


29,950



20,437



15,299Rocky Mountains






8



Total operations and maintenance expenses

$
54,561


$
41,156


$
32,484  60




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##### Table of Contents



(1)
    
    Total segment gross margin is a non-GAAP financial measure. The
    following is a reconciliation of total segment gross margin to
    its most directly comparable GAAP measure of operating income.  Year Ended December 31,2008

2007

2006(In thousands)Reconciliation of total segment gross margin to operating income:Operating income

$
107,994


$
91,386


$
96,312Operations and maintenance expenses


54,561



41,156



32,484Depreciation, amortization and impairment


53,154



39,967



31,993General and administrative expenses


45,571



34,638



26,535Taxes other than income


3,019



2,637



2,061Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Total segment gross margin

$
257,410


$
206,934


$
188,088   (2)
    
    Corporate and other includes results attributable to
    Copanos commodity risk management activities.(3)
    
    Excludes volumes associated with our interest in Southern Dome.
    For the year ended December 31, 2008, plant inlet volumes
    for Southern Dome averaged 9,923 MMBtu/d and NGLs produced
    averaged 364 Bbls/d. 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.(4)
    
    Producer services throughput consists of volumes we purchased
    for resale, volumes gathered under our firm capacity gathering
    agreements with Fort Union and volumes transported using
    our firm capacity agreements with WIC. Excludes results and
    volumes associated with our interests in Bighorn and
    Fort Union. Volumes transported by Bighorn and
    Fort Union were 214,791 MMBtu/d and
    731,134 MMBtu/d, respectively, for the year ended
    December 31, 2008. 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.(5)
    
    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, 2008, Plant inlet volumes
    averaged 114,142 MMBtu/d and NGLs produced averaged
    11,570 Bbls/d for plants owned by the Oklahoma segment. 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.(6)
    
    Excludes results and volumes associated with our interest in
    Webb Duval. Volumes transported by Webb Duval, net of
    intercompany volumes, were 91,342 MMBtu/d,
    93,887 MMBtu/d and 117,303 MMBtu/d for the years ended
    December 31, 2008, 2007 and 2006 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 596,535 MMBtu/d
    and NGLs produced averaged 14,715 barrels per day for the
    year ended December 31, 2008 for plants owned by the Texas
    segment. 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. 61




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##### Table of Contents



Year
    Ended December 31, 2008 Compared with Year Ended
    December 31, 2007
    
    an increase in total segment gross margin of $50.5 million,
    primarily as a result of a $46.8 million increase in
    operating segment gross margin reflecting higher average
    commodity prices year over year and increased service
    throughput, and a $3.7 million improved contribution from
    our commodity risk management activities;
    an increase in operations, maintenance and depreciation expenses
    of $33.4 million, primarily related to expanded operations
    in north Texas, full year activities of the Rocky Mountains
    segment, increases in labor, compression, chemicals, utility and
    repair and maintenance expenses and the effects of Hurricane Ike;
    an increase in equity in earnings of our unconsolidated
    affiliates of $4.7 million, primarily related to the Rocky
    Mountains acquisition;
    the gain of $15.3 million related to the repurchase and
    retirement of the senior unsecured notes previously discussed;
    non-cash charges totaling $15.8 million related to
    (a) $10.0 million of mark-to-market losses on
    Copanos undesignated interest rate swaps,
    (b) $3.5 million of goodwill impairment related to the
    Rocky Mountains acquisition and additional amortization of the
    basis differential on our investment in Bighorn, (c) a
    $1.3 million write-off of certain accounts receivable
    balances and (d) a $1.0 million write-off of debt
    issuance costs related to the repurchase and retirement of our
    senior unsecured notes;
    an increase in interest expense of $24.6 million as a
    result of increased average outstanding borrowings from 2007 to
    2008 ($721 million in 2008 compared to $376 million in
    2007); and
    a decrease in interest income of $1.7 million.  Oklahoma Segment Gross Margin.
  Texas Segment Gross Margin.
  Rocky Mountains Segment Gross Margin.
  Corporate and Other.
 62




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Operations and Maintenance
    Expenses.
  Depreciation, Amortization and
    Impairment.
  General and Administrative Expenses.
  Interest and Other Financing Costs.
  Gain on Unsecured Debt Retirement.
 63




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##### Table of Contents



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.
  Corporate and Other.
  Operations and Maintenance
    Expenses.
  Depreciation, Amortization and
    Impairment.
  General and Administrative Expenses.
 64




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##### Table of Contents



Interest and Other Financing Costs.
  Cash
    Flows
    Year Ended December 31,2008


2007


2006(In thousands)Net cash provided by operating activities

$
89,924


$
128,218


$
91,679Net cash used in investing activities


(198,855
)


(727,052
)


(70,291
)Net cash provided by (used in) financing activities


99,950



632,015



(7,201
)     Operating Cash Flows.
  
    cash distributions received from our unconsolidated affiliates
    (Bighorn, Fort Union, Webb Duval and Southern Dome) were
    $18.8 million higher in 2008 compared to 2007; offset by:
    operating income (adjusted for the timing of related cash
    receipts and disbursements) was $10.5 million lower in 2008
    compared with 2007;
    risk management activities used $21.8 million more of cash
    flow in 2008 as compared to 2007 as a result of expanding our
    commodity derivative portfolio in 2008; and
    interest payments under our credit arrangements in 2008 were
    $24.8 million higher compared to 2007. 65




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##### Table of Contents




    cash distributions from our unconsolidated affiliates (Webb
    Duval and Southern Dome)were $3.7 million higher in 2007
    compared to 2006;
    operating income (adjusted for the timing of related cash
    receipts and disbursements, including our risk management
    activities) was $13.0 million higher in 2007 compared to
    2006;
    risk management activities contributed $17.4 million more
    of cash flow in 2007 as compared to 2006 as a result of the
    expiration of a portion of our commodity derivative portfolio in
    2007; and
    interest payments under our credit arrangements in 2007 were
    $2.4 million lower compared to 2006.  Investing Cash Flows.
    11-mile 8-mile
  Financing Cash Flows.
     66




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##### Table of Contents



Liquidity
    and Capital Resources
  Sources of Liquidity.
  Effects of Economic Changes in 2008.
    Outlook. and/or
  Capital Expenditures.
  
    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, which are 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. 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. 67




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##### Table of Contents



Cash Distributions.
  One Quarter


Four QuartersCommon
    units(1)

$
31,466


$
125,863     (1)
    
    Includes distributions on
    restricted common units and phantom units issued under our
    Long-Term Incentive Plan (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 2, 2009, we had 169,709
    outstanding restricted units and 587,410 outstanding phantom
    units.  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

$
820,415


$



$



$
220,000


$
600,415Interest(1)


413,591



54,204



108,704



100,669



150,014Gathering and transportation firm commitments


140,474



21,223



30,193



33,664



55,394Operating leases


10,516



4,796



3,519



1,360



841Capital
    expenditures(2)


11,607



11,607











Total contractual cash
    obligations(1)

$
1,396,603


$
91,830


$
142,416


$
355,693


$
806,664     (1)
    
    These amounts exclude estimates of
    the effect of our interest rate swap contracts on our future
    interest obligations. As of December 31, 2008, the fair
    value of our interest rate swap contracts, which expire between
    July 2010 and October 2012, totaled $11.1 million.(2)
    
    These amounts include the required
    capital expenditures we have committed to for the completion of
    the Saint Jo processing plant and other capital projects.   68




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Our
    Indebtedness
    Credit Ratings.
  Revolving Credit Facility.
          
    a minimum EBITDA to interest expense ratio (using four
    quarters EBITDA as defined under the revolving credit
    facility) of 2.5 to 1.0; and 69




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##### Table of Contents




    a maximum total debt to EBITDA ratio of 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, within specified
    grace periods, any interest, fees or other amounts;
    failure to perform or otherwise comply with the covenants in the
    credit agreement or other loan documents, subject to 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;
    our inability to demonstrate compliance with financial covenants
    within a specified period after Bighorn or Fort Union is
    prohibited from making a distribution to its members;
    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 revolving credit
    facility).    Senior Notes.
          
    sell assets; 70




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##### Table of Contents




    redeem or repurchase equity or 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.    Impact of
    Inflation
    Off-Balance
    Sheet Arrangements
    Recent
    Accounting Pronouncements
  Business
    Combinations
  Business Combinations
  Fair
    Value Measurements
  Fair Value Measurements. Accounting for Derivative Instruments and Hedging
    Activities,
  No. SFAS 157-2, Effective Date of FASB Statement No. 157,
 71




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##### Table of Contents



Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
  Disclosures
    about Derivative Instruments and Hedging Activities 
    an amendment of FASB Statement No. 133
  Disclosures about Derivative Instruments and Hedging
    Activities  an amendment of FASB Statement
    No. 133.
  Useful
    Life of Intangible Assets
  No. 142-3, Determination of the Useful Life of Intangible
    Assets, Goodwill and Other
    Intangible Assets. No. 142-3
  Critical
    Accounting Policies and Estimates
    Impairment of Long-Lived Assets. Accounting for the
    Impairment or Disposal of Long-Lived Assets
 72




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##### Table of Contents




    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.    Impairment of Goodwill.
  Investments in Unconsolidated Affiliates Equity Method of Accounting.
  Revenue Recognition. customer-by-customer
   73




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##### Table of Contents



agreed-upon
  
    Fee-Based Arrangements.  Under fee-based
    arrangements, producers or shippers pay us an agreed rate per
    unit of throughput to gather or transport their natural gas. The
    agreed rate may be a fixed fee or based upon a percentage of
    index price.
    Percentage-of-Proceeds Arrangements.  Under
    percentage-of-proceeds arrangements, we generally gather and
    process natural gas on behalf of producers and sell the residue
    gas and NGL volumes at index-related prices. We remit to
    producers an agreed upon percentage of the proceeds we receive
    from the sale of residue gas and NGLs.
    Percentage-of-Index Arrangements.  Under
    percentage-of-index arrangements, we purchase natural gas at
    either (i) a percentage discount to a specified index
    price, (ii) a specified index price less a fixed amount or
    (iii) a percentage discount to a specified index price less
    an additional fixed amount. We then gather, deliver and resell
    the natural gas at an index-based price.
    Keep-Whole with Fee Arrangements.  Under
    keep-whole with fee arrangements, we receive natural gas from
    producers and third-party transporters, either process or
    condition the natural gas at our election, sell the resulting
    NGLs to third parties at market prices for our account and
    redeliver the residue gas to the producer or third-party
    transporter. Because the extraction of NGLs from the natural gas
    during processing or conditioning reduces the Btus of the
    natural gas, we also must purchase natural gas at market prices
    for return to producers or third-party transporters to keep them
    whole. Under our keep-whole with fee arrangements, we also
    charge producers and third-party transporters a conditioning
    fee, at all times or in certain circumstances depending upon the
    terms of the particular contract. These fees provide us
    additional revenue and compensate us for the services required
    to redeliver natural gas that meets downstream pipeline quality
    specifications. It is generally not our policy to enter into new
    keep-whole contracts without fee arrangements or pricing
    provisions that provide positive gross margins during
    conditioning periods.  Forward-Looking
    Statements
   74




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##### Table of Contents




    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;
    the availability of local, intrastate and interstate
    transportation systems and other facilities for natural gas and
    NGLs;
    our ability to access our revolving credit facility and to
    obtain additional financing on acceptable terms;
    the effectiveness of our hedging program;
    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.   75




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##### Table of Contents



Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk      Commodity
    Price Risk
    Oklahoma. agreed-upon
  Texas.
    Rocky Mountains.
  Other Commodity Price Risks.
 76




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##### Table of Contents



Sensitivity.
  Risk
    Management Oversight
      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; 77




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##### Table of Contents




    Except as provided in the policy amendment described below, we
    may not (i) purchase crude oil or natural gas liquids put
    options, (ii) purchase natural gas put or call options,
    (iii) purchase fractionation spread or processing margin
    spread put options or (iv) enter into any crude oil,
    natural gas or natural gas liquids spread options permitted by
    the policy if, as a result of the proposed transaction, net
    notional hedged volumes with respect to the underlying hedged
    commodity would be an amount in excess of 80% of the projected
    requirements or output, as applicable, for the hedged period (a
    calendar year or any remaining portion thereof). Notwithstanding
    this limitation, we are not required to divest outstanding hedge
    positions except to the extent net notional hedged volumes with
    respect to an underlying hedged commodity exceed 100% of the
    projected requirements or output, as applicable, for the hedged
    period; and
    The aggregate volumetric exposure associated with swaps, collars
    and written calls relating to any product must not exceed the
    lesser of 50% of the aggregate hedged position or 35% of the
    projected requirements or output with respect to such product.          Oklahoma Segment.
  Texas Segment.
 78




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##### Table of Contents



Rocky Mountains Segment.
  Our
    Commodity Hedge Portfolio
    Purchased
    CenterPoint East Natural Gas Puts
  Put Strike


Put Volumes(Per MMBtu)


(MMBtu/d)2009

$
6.95



5,000   Purchased
    HSC Index Natural Gas Options
  Call Spread


CallCall Strike


Call Volumes


Strike


Volume(Per MMBtu)


(MMBtu/d)


(Per MMBtu)


(MMBtu/d)Bought


Sold2009

$
7.75


$
10.00



8,000


$
10.00



10,0002010

$
7.35


$
10.00



7,100


$
10.00



10,0002011

$
6.95


$
10.00



7,100


$
10.00



10,000   Purchased
    Mt. Belvieu Purity Ethane Puts and Entered into Swaps
  Put


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2009

$
0.5900



2,200


$
0.6025



1,1002010

$
0.5550



1,600


$
0.5700



5002011

$
0.5300



1,700


$
0.5450



500   Purchased
    Mt. Belvieu Purity Ethane Put Spread Options
  Put SpreadStrike(Per gallon)


VolumesBought


Sold


(Bbls/d)2009

$
0.83


$
0.590



1,1002009

$
0.79


$
0.590



1,100  79




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##### Table of Contents



Purchased
    Mt. Belvieu TET Propane Puts and Entered into Swaps
  Put


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2009

$
0.8725



2,200







2009

$
0.9650



1,000


$
1.0275



1,0002010

$
0.8500



1,100







2010

$
0.9460



700


$
0.9925



7002011

$
0.8265



1,100







2011

$
0.9340



700


$
0.9750



7002011

$
1.3300



900







   Purchased
    Mt. Belvieu TET Propane Put Spread Options
  Put SpreadStrike(Per gallon)


VolumesBought


Sold


(Bbls/d)2009

$
1.33


$
0.8725



1,6002009

$
1.33


$
0.8725



6002009

$
1.33


$
0.9650



1002010

$
1.49


$
0.8500



1,1002010

$
1.49


$
0.9460



700   Purchased
    Mt. Belvieu Non-TET Isobutane Puts and Entered into
    Swaps
  Put


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2009

$
1.0600



450







2009

$
1.1600



100


$
1.2425



1002010

$
1.0350



300







2010

$
1.1145



100


$
1.2025



1002011

$
1.0205



300







2011

$
1.1100



100


$
1.1800



1002011

$
1.7100



200







   Purchased
    Mt. Belvieu Non-TET Isobutane Put Spread Options
  Put SpreadStrike(Per gallon)


VolumesBought


Sold


(Bbls/d)2009

$
1.62


$
1.0600



1752009

$
1.57


$
1.0600



2752009

$
1.62


$
1.1600



1002010

$
1.89


$
1.1145



1002010

$
1.89


$
1.0350



300  80




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##### Table of Contents



Purchased
    Mt. Belvieu Non-TET Normal Butane Puts and Entered into
    Swaps
  Put


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2009

$
1.0525



700







2009

$
1.1400



400


$
1.2275



4002009









$
(1.7025
)


(320
)2010

$
1.0300



300







2010

$
1.1000



200


$
1.1850



2002011

$
1.0205



300







2011

$
1.0850



200


$
1.1700



2002011

$
1.7100



350







   Purchased
    Mt. Belvieu Non-TET Normal Butane Put Spread Options
  Put SpreadStrike(Per gallon)


VolumesBought


Sold


(Bbls/d)2009

$
1.58


$
1.0525



1502009

$
1.54


$
1.0525



5502009

$
1.58


$
1.1400



2002010

$
1.88


$
1.1000



2002010

$
1.88


$
1.0300



300   Purchased
    Mt. Belvieu Non-TET Natural Gasoline Puts and Entered into
    Swaps
  Put


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2009

$
1.440



200


$
1.540



2002010

$
1.408



300







2011

$
1.410



300







   Purchased
    Mt. Belvieu Non-TET Natural Gasoline Put Spread
    Options
  Put SpreadStrike(Per gallon)


VolumesBought


Sold


(Bbls/d)2009

$
1.98


$
1.440



1202010

$
2.54


$
1.408



300  81




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##### Table of Contents



Purchased
    WTI Crude Oil Puts
  PutStrike


Volumes(Per barrel)


(Bbls/d)2009

$
55.00



1,0002009

$
60.00



5002010

$
55.00



1,0002010

$
60.00



4002011

$
55.00



1,0002011

$
60.00



400   Purchased
    WTI Crude Oil Put Spread Options
  Put SpreadStrike(Per barrel)


VolumesBought


Sold


(Bbls/d)2009

$
86.50


$
55.00



7502009

$
92.00


$
55.00



2502009

$
92.00


$
60.00



5002010

$
118.00


$
55.00



1,0002010

$
118.00


$
60.00



400     Interest
    Rate Risk
         82




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##### Table of Contents



Counterparty
    Risk
        Item 8.
    Financial
    Statements and Supplementary Data    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
   83




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##### Table of Contents



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
   84




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##### Table of Contents



MANAGEMENTS
    ANNUAL REPORT ON INTERNAL CONTROL
    OVER FINANCIAL REPORTING
    AS OF DECEMBER 31, 2008
  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  85




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
     Internal Control  Integrated Framework
        Internal Control  Integrated Framework
    
    Item 9B.
    Other
    Information   86




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##### Table of Contents



PART III  Item 10.
    Directors
    and Executive Officers of the Registrant    Item 11.
    Executive
    Compensation    Item 12.
    Security
    Ownership of Certain Beneficial Owners and Management and
    Related Unitholder Matters    Item 13.
    Certain
    Relationships and Related Parties    Item 14.
    Principal
    Accountant Fees and Services   87




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##### Table of Contents



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

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).4
.7

Indenture, dated May 16, 2008, among Copano Energy, L.L.C.,
    Copano Energy Finance Corporation, the Subsidiary Guarantors
    named therein and U.S. Bank National Association, as trustee
    (incorporated by reference to Exhibit 4.1 to Current Report
    on
    Form 8-K
    filed May 19, 2008).4
.8

Form of Global Note representing 7.75% Senior Notes due
    2018 (included in 144A/Regulation S Appendix to
    Exhibit 4.7 above). 88




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##### Table of Contents



Number

Description4
.9

Registration Rights Agreement, dated May 16, 2008, among
    Copano Energy, L.L.C., Copano Energy Finance Corporation, the
    Subsidiary Guarantors named therein and the Initial Purchasers
    named therein (incorporated by reference to Exhibit 4.2 to
    Current Report on
    Form 8-K
    filed May 19, 2008).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).10
.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

Third Amendment to Copano Energy, L.L.C. Long-Term Incentive
    Plan, dated November 18, 2008 (incorporated by reference to
    Exhibit 99.1 to Current Report on
    Form 8-K
    filed November 25, 2008).10
.5

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
.6

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
.7

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
.8

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
.9

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
.10

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
.11

Third Amendment to Employment Agreement between CPNO Services,
    L.P., R. Bruce Northcutt and the Copano Controlling Entities,
    effective November 18, 2008 (incorporated by reference to
    Exhibit 99.2 to Annual Report on
    Form 10-K
    filed November 25, 2008).10
.12

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
.13

First Amendment to Employment Agreement between CPNO Services,
    L.P. and John A. Raber effective November 19, 2008
    (incorporated by reference to Exhibit 99.2 to Annual Report
    on
    Form 10-K
    filed November 25, 2008).10
.14

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
.15*

First Amendment to Employment Agreement between ScissorTail
    Energy, L.L.C. and Sharon Robinson dated as of December 31,
    2008.10
.16

Retirement, Release and Consulting Services Agreement, dated
    May 15, 2008, between Copano Energy, L.L.C. and Ronald W.
    Bopp (incorporated by reference to Exhibit 10.5 to
    Quarterly Report on
    Form 10-Q
    filed August 8, 2008).10
.17

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
.18

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
.19

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
.20

2005 Form of Unit Option Grant (incorporated by reference to
    Exhibit 4.5 to Registration Statement on
    Form S-8
    filed February 11, 2005). 89




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##### Table of Contents



Number

Description10
.21

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).10
.22

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
.23

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
.24

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
.25

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
.26

November 2006 Form of Restricted Unit Grant (Directors)
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed November 20, 2006).10
.27

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
.28

2008 Form of Phantom Unit Grant (Employees) (incorporated by
    reference to Exhibit 10.1 to Current Report on
    Form 8-K
    filed June 6, 2008).10
.29

2008 Form of Performance Based Phantom Unit Grant (Employees)
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed June 6, 2008).10
.30

2008 Form of Long-Term Retention Award Grant (Employees)
    (incorporated by reference to Exhibit 10.3 to Current
    Report on
    Form 8-K
    filed June 6, 2008).10
.31

2008 Form of Phantom Unit Grant (Employee Bonus Awards)
    (incorporated by reference to Exhibit 99.2 to Current
    Report on
    Form 8-K
    filed November 12, 2008).10
.32

2008 Form of Restricted Unit Grant (Directors) (incorporated by
    reference to Exhibit 99.4 to Current Report on
    Form 8-K
    filed November 25 2008).10
.33

Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 99.1 to Current
    Report on
    Form 8-K
    filed November 12, 2008).10
.34

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
.35

Copano Energy, L.L.C. Deferred Compensation Plan dated
    December 16, 2008 (incorporated by reference to
    Exhibit 99.1 to Current Report on
    Form 8-K
    filed December 19, 2008).10
.36

Form of Deferred Compensation Plan Participation Agreement
    (incorporated by reference to Exhibit 99.2 to Current
    Report on
    Form 8-K
    filed December 19, 2008).10
.37

Form of Deferred Compensation Plan Chief Executive Officer
    Participation Agreement (incorporated by reference to
    Exhibit 99.3 to Current Report on
    Form 8-K
    filed December 19, 2008).10
.38

Form of Indemnification Agreement (incorporated by reference to
    Exhibit 10.1 to Current Report on
    Form 8-K
    filed November 2, 2005).10
.39

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
.40

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
.41

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
.42

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
.43

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). 90




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##### Table of Contents



Number

Description10
.44

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
.45

First Amendment to Amended and Restated Credit Agreement, dated
    October 19, 2007. (incorporated by reference to
    Exhibit 10.40 to Annual Report on
    Form 10-K
    filed February 29, 2008).10
.46

Purchase Agreement, dated May 13, 2008, among Copano
    Energy, L.L.C., Copano Energy Finance Corporation, the
    Subsidiary Guarantors named therein and the Initial Purchasers
    named therein (incorporated by reference to Exhibit 10.1 to
    Current Report on
    Form 8-K
    filed May 19, 2008).21
.1

List of Subsidiaries (incorporated by reference to
    Exhibit 21.1 to Annual Report on
    Form 10-K
    filed February 29, 2008).23
.1*

Consent of Deloitte & Touche LLP.31
.1*

Sarbanes-Oxley Section 302 certification of John R. Eckel,
    Jr. (Chief Executive Officer) for Copano Energy, L.L.C.31
.2*

Sarbanes-Oxley Section 302 certification of Matthew J.
    Assiff (Chief Financial Officer) for Copano Energy, L.L.C.32
.1*

Sarbanes-Oxley Section 906 certification of John R. Eckel,
    Jr. (Chief Executive Officer) for Copano Energy, L.L.C.32
.2*

Sarbanes-Oxley Section 906 certification of Matthew J.
    Assiff (Chief Financial Officer) for Copano Energy, L.L.C.     *
    
    Filed herewith.
    
    Portions of this exhibit have been omitted pursuant to a request
    for confidential treatment.  (b)
    Exhibits   91




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##### Table of Contents



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

Title

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

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

February 27, 2009/s/  Matthew
    J. AssiffMatthew
    J. Assiff

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

February 27, 2009/s/  Lari
    ParadeeLari
    Paradee

Vice President and Controller (Principal Accounting Officer)

February 27, 2009/s/  James
    G. CrumpJames
    G. Crump

Director

February 27, 2009/s/  Ernie
    L. DannerErnie
    L. Danner

Director

February 27, 2009/s/  Michael
    L. JohnsonMichael
    L. Johnson

Director

February 27, 2009/s/  Scott
    A. GriffithsScott
    A. Griffiths

Director

February 27, 2009/s/  T.
    William PorterT.
    William Porter

Director

February 27, 2009/s/  William
    L. ThackerWilliam
    L. Thacker

Director

February 27, 2009  92




---



##### 



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


F-2Consolidated Balance Sheets as of
    December 31, 2008 and 2007


F-3Consolidated Statements of Operations for the
    years ended December 31, 2008, 2007 and 2006


F-4Consolidated Statements of Cash Flows for the
    years ended December 31, 2008, 2007 and 2006


F-5Consolidated Statements of Members Capital
    and Comprehensive Income (Loss) for the years ended
    December 31, 2008, 2007 and 2006


F-6Notes to Consolidated Financial Statements


F-7Bighorn Gas Gathering, L.L.C. Financial Statements:Independent Auditors Report


F-54Balance Sheets as of December 31, 2008
    (unaudited) and 2007


F-55Statement of Operations for the year ended
    December 31, 2008 (unaudited) and the period from
    October 1, 2007 through December 31, 2007


F-56Statement of Cash Flows for the year ended
    December 31, 2008 (unaudited)and the period from
    October 1, 2007 through December 31, 2007


F-57Statement of Members Equity for the year
    ended December 31, 2008 (unaudited) and the period from
    October 1, 2007 through December 31, 2008


F-58Notes to Financial Statements


F-59   F-1




---



##### Table of Contents



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




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
 CONSOLIDATED
    BALANCE SHEETS  December 31,2008


2007(In thousands,except unit information)ASSETSCurrent assets:Cash and cash equivalents

$
63,684


$
72,665Accounts receivable, net


96,028



127,534Risk management assets


76,440



3,289Prepayments and other current assets


5,004



3,881Total current assets


241,156



207,369Property, plant and equipment, net


823,574



694,727Intangible assets, net


198,974



200,546Investment in unconsolidated affiliates


640,598



632,725Escrow cash


1,858



Risk management assets


82,892



10,598Other assets, net


24,613



23,118Total assets

$
2,013,665


$
1,769,083LIABILITIES AND MEMBERS CAPITALCurrent liabilities:Accounts payable

$
103,849


$
147,046Accrued interest


11,904



11,319Accrued tax liability


784



3,919Risk management liabilities


6,272



27,710Other current liabilities


16,787



12,931Total current liabilities


139,596



202,925Long-term debt (includes $704 and $773 bond premium as of
    December 31, 2008 and 2007, respectively)


821,119



630,773Deferred tax provision


1,718



1,231Risk management and other noncurrent liabilities


13,274



40,018Commitments and contingencies (Note 13)Members capital:Common units, no par value, 53,965,288 units and
    47,366,048 units issued and outstanding as of
    December 31, 2008 and 2007, respectively


865,343



661,585Class C units, no par value, 394,853 units and
    1,184,557 units issued and outstanding as of
    December 31, 2008 and 2007, respectively


13,497



40,492Class D units, no par value, 3,245,817 units issued
    and outstanding as of December 31, 2008 and 2007


112,454



112,454Class E units, no par value, 0 units and
    5,598,836 units issued and outstanding as of
    December 31, 2008 and 2007, respectively






175,634Paid-in capital


33,734



23,773Accumulated deficit


(54,696
)


(7,867
)Other comprehensive income (loss)


67,626



(111,935
)1,037,958



894,136Total liabilities and members capital

$
2,013,665


$
1,769,083    F-3




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
 CONSOLIDATED
    STATEMENTS OF OPERATIONS Year Ended December 31,2008


2007


2006(In thousands,except per unit information)Revenue:Natural gas sales

$
747,258


$
518,431


$
448,054Natural gas liquids sales


597,986



491,432



369,892Crude oil sales


174,667



77,142



Transportation, compression and processing fees


59,006



22,306



16,232Condensate and other


50,169



32,349



26,094Total revenue


1,629,086



1,141,660



860,272Costs and expenses:Cost of natural gas and natural gas
    liquids(1)


1,178,304



853,964



669,158Cost of crude oil
    purchases(1)


171,401



73,814



Transportation(1)


21,971



6,948



3,026Operations and maintenance


54,561



41,156



32,484Depreciation, amortization and impairment


53,154



39,967



31,993General and administrative


45,571



34,638



26,535Taxes other than income


3,019



2,637



2,061Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Total costs and expenses


1,521,092



1,050,274



763,960Operating income


107,994



91,386



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


1,174



2,854



1,706Gain on retirement of unsecured debt


15,272







Interest and other financing costs


(64,978
)


(29,351
)


(32,904
)Income before income taxes


59,462



64,889



65,114Provision for income taxes


(1,249
)


(1,714
)


Net income

$
58,213


$
63,175


$
65,114Basic net income per common unit:Net income per common unit

$
1.20


$
1.48


$
1.77Weighted average number of common units


48,513



42,456



29,752Diluted net income per common unit:Net income per common unit

$
1.01


$
1.36


$
1.75Weighted average number of common units


57,856



46,516



30,180Basic net income per subordinated unit:Net income per subordinated unit

$



$
0.21


$
1.77Weighted average number of subordinated units






848



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

$



$
0.21


$
1.76Weighted average number of subordinated units






848



7,038     (1)
    
    Exclusive of operations and maintenance and depreciation,
    amortization and impairment shown separately below.   F-4




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
 CONSOLIDATED
    STATEMENTS OF CASH FLOWS  Year Ended December 31,2008


2007


2006(In thousands)Cash Flows From Operating Activities:Net income

$
58,213


$
63,175


$
65,114Adjustments to reconcile net income to net cash provided by
    operating activities:Depreciation and amortization


50,314



39,967



31,993Impairment of goodwill


2,840







Amortization of debt issue costs


4,467



1,666



4,462Equity in earnings from unconsolidated affiliates


(6,889
)


(2,850
)


(1,297
)Distributions from unconsolidated affiliates


22,460



3,706



Gain on retirement of Senior Notes (Note 7)


(15,272
)






Noncash loss on risk management activities, net


12,751



10,248



353Equity-based compensation


5,858



3,223



1,910Deferred tax provision


486



1,231



Other noncash items


98



(136
)


176Changes in assets and liabilities, net of acquisitions:Accounts receivable


32,090



(34,890
)


16,459Prepayments and other current assets


(1,123
)


(204
)


1,372Risk management activities


(27,037
)


(5,201
)


(22,585
)Accounts payable


(44,766
)


38,232



(6,867
)Other current liabilities


(4,566
)


10,051



589Net cash provided by operating activities


89,924



128,218



91,679Cash Flows From Investing Activities:Additions to property, plant and equipment


(152,533
)


(80,898
)


(49,033
)Additions to intangible assets


(9,189
)


(3,406
)


(1,237
)Acquisitions, net of cash acquired


(12,655
)


(641,097
)


(9,074
)Investment in unconsolidated affiliates


(26,832
)


(1,727
)


(10,438
)Distributions from unconsolidated affiliates


3,370



676



Escrow cash


(1,858
)






Other


842



(600
)


(509
)Net cash used in investing activities


(198,855
)


(727,052
)


(70,291
)Cash Flows From Financing Activities:Proceeds from long-term debt


579,000



663,781



363,500Repayments of long-term debt


(339,000
)


(288,000
)


(506,500
)Retirement of Senior Notes


(34,313
)






Repayment of short-term notes payable






(1,495
)


(1,842
)Deferred financing costs


(6,688
)


(10,677
)


(7,035
)Distributions to unitholders


(104,234
)


(73,629
)


(46,977
)Proceeds from follow-on public offering of common units, net of
    underwriting discounts and commissions of $7,216










162,725Proceeds from private placement of common units






157,125



25,000Proceeds from private placement of Class E units






177,875



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


4,103



9,965



4,607Equity offering costs


(47
)


(4,741
)


(1,057
)Proceeds from option exercises


1,129



1,811



378Net cash provided by (used in) financing activities


99,950



632,015



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


(8,981
)


33,181



14,187Cash and cash equivalents, beginning of year


72,665



39,484



25,297Cash and cash equivalents, end of year

$
63,684


$
72,665


$
39,484    F-5




---



##### Table of Contents



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


Class C


Class D


Class E


Subordinated





Accumulated





Other





TotalNumber


Common


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


Capital


(Deficit)


Compensation


Income (Loss)


Total


Income (Loss)Balance, December 31, 2005


28,202


$
297,592






$







$







$




7,038


$
10,379


$
4,068


$
(14,941
)

$
(3,949
)

$
(11,346
)

$
281,803


$
Capital 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
)


894,136Capital contributions from Pre-IPO Investors










































4,103















4,103


$
Conversion of Class C units into common units


789



26,995



(789
)


(26,995
)














































Conversion of Class E units into common units


5,599



175,634



















(5,599
)


(175,634
)






























Distributions to unitholders














































(105,042
)










(105,042
)


Option exercises


72



1,129



















































1,129



Equity-based compensation










































5,858















5,858



Vested restricted units


89



























































Units issued for vested phantom units


50



























































Net income














































58,213











58,213



58,213Derivative settlements reclassified to income






















































45,529



45,529



45,529Unrealized gain-change in fair value of derivatives






















































134,032



134,032



134,032Comprehensive income





























































$
237,774Balance, December 31, 2008


53,965


$
865,343



395


$
13,497



3,246


$
112,454


















$
33,734


$
(54,696
)

$



$
67,626


$
1,037,958    F-6




---



##### Table of Contents



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




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Use of
    Estimates
    Cash
    and Cash Equivalents
    Concentration
    and Credit Risk
        Allowance
    for Doubtful Accounts
   F-8




---



##### Table of Contents



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





Write-Offs,


Balance atBeginning


Charged to


Net of


End ofof Period


Expense


Recoveries


PeriodYear ended December 31, 2008

$
166


$
1,269


$
(1,347
)

$
88Year ended December 31, 2007


64



69



33



166Year ended December 31, 2006


64



42



(42
)


64   Property,
    Plant and Equipment
    Useful LivesPipelines and equipment


15-30 yearsGas processing plants and equipment


20-30 yearsOther property and equipment


3-7 years     Intangible
    Assets
  2009  2010  2011  2012  2013 
  December 31,2008


2007Rights-of-way and easements, at cost

$
113,309


$
104,427Less accumulated amortization for rights-of-way and easements


(11,926
)


(8,922
)Contracts


107,916



107,906Less accumulated amortization for contracts


(14,901
)


(7,675
)Customer relationships


5,318



5,204Less accumulated amortization for customer relationships


(742
)


(394
)Intangible assets, net

$
198,974


$
200,546    F-9




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Asset
    Impairment
    Goodwill
  Goodwill and Other Intangible Assets,
  Other
    Assets
    Transportation
    and Exchange Imbalances
    Asset
    Retirement Obligations
   F-10




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Revenue
    Recognition
  customer-by-customer
      agreed-upon
  
    Fee-Based Arrangements.  Under fee-based
    arrangements, producers or shippers pay us an agreed rate per
    unit of throughput to gather or transport their natural gas. The
    agreed rate may be a fixed fee or based upon a percentage of
    index price.
    Percentage-of-Proceeds Arrangements.  Under
    percentage-of-proceeds arrangements, we generally gather and
    process natural gas on behalf of producers and sell the residue
    gas and NGL volumes at index-related prices. We remit to
    producers an agreed upon percentage of the proceeds we receive
    from the sale of residue gas and NGLs.
    Percentage-of-Index Arrangements.  Under
    percentage-of-index arrangements, we purchase natural gas at
    either (i) a percentage discount to a specified index
    price, (ii) a specified index price less a fixed amount or
    (iii) a percentage discount to a specified index price less
    an additional fixed amount. We then gather, deliver and resell
    the natural gas at an index-based price.
    Keep-Whole with Fee Arrangements.  Under
    keep-whole with fee arrangements, we receive natural gas from
    producers and third-party transporters, either process or
    condition the natural gas at our election, sell the resulting
    NGLs to third parties at market prices for our account and
    redeliver the residue gas to the F-11




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Derivatives
  Accounting for Derivative
    Instruments and Hedging Activities,
      Interest
    and Other Financing Costs
    Income
    Taxes
   F-12




---



##### Table of Contents



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




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Year Ended December 31,2008


2007


2006(In thousands, except per unit information)Net income

$
58,213


$
63,175


$
65,114Less net income attributable to subordinated units






(175
)


(12,457
)Net income available  basic common units


58,213



63,000



52,657Net income reallocated from subordinated units






175



39Net income available  diluted common
    units(1)

$
58,213


$
63,175


$
52,696Basic weighted average common units


48,513



42,456



29,752Dilutive weighted average common
    units(1)(2)


57,856



46,516



30,180Basic net income per common unit

$
1.20


$
1.48


$
1.77Diluted net income per common
    unit(1)(2)

$
1.01


$
1.36


$
1.75     (1)
    
    Our potentially dilutive common equity includes the following:  Year EndedDecember 31,2008


2007


2006(In thousands)Employee options


326



537



318Restricted units


47



138



110Phantom units


19







Contingent incentive plan unit awards


198







Class C units


812



743



Class D units


3,246



658



Class E units


4,696



1,135



     (2)
    
    The following potentially dilutive common equity was excluded
    from the dilutive net income per unit calculation because to
    include these equity securities would have been anti-dilutive:  Year Ended December 31,2008


2007


2006(In thousands)Employee options


1,085



906



895Restricted units


123



103



206Phantom Units


570



101



   Share-Based
    Payment
  Share-Based
    Payment.
   F-14




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    Note 3 
    New
    Accounting Pronouncements  Business
    Combinations
  Business Combinations
  Fair
    Value Measurements
  Fair Value Measurements. Accounting for Derivative Instruments and Hedging
    Activities,
  No. SFAS 157-2, Effective Date of FASB Statement No. 157,
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
  Disclosures
    about Derivative Instruments and Hedging Activities 
    an amendment of FASB Statement No. 133
  Disclosures about Derivative Instruments and Hedging
    Activities  an amendment of FASB Statement
    No. 133.
 F-15




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 3 
    New
    Accounting Pronouncements (Continued)    Useful
    Life of Intangible Assets
  No. 142-3, Determination of the Useful Life of Intangible
    Assets, Goodwill and Other
    Intangible Assets. No. 142-3
  Note 4 
    Acquisitions  Acquisition
    of Cantera Natural Gas LLC
        Purchase price for the Cantera Acquisition

$
675,000Net working capital adjustments


45,773Acquisition costs


12,013Total purchase price for the Cantera Acquisition

$
732,786  F-16




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)    Cash and cash equivalents

$
37,175Accounts receivable


14,149Prepayments and other current assets


117Property, plant and equipment


13,551Intangibles


62,522Goodwill (Note 2)


2,840Other assets


81Investment in unconsolidated affiliates


613,448Accounts payable


(4,289
)Other current liabilities


(6,651
)Other noncurrent liabilities


(157
)$
732,786     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


477Goodwill


518Investment in unconsolidated affiliates


77Accounts payable


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




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##### Table of Contents



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  F-18




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)  2008
    Acquisitions
    Note 5 
    Property,
    Plant and Equipment and Asset Retirement Obligations    December 31,2008


2007Property, plant and equipment, at costPipelines and equipment

$
721,725


$
647,188Gas processing plant and equipment


148,482



96,448Construction in progress


80,901



42,452Office furniture and equipment


7,438



5,203958,546



791,291Less accumulated depreciation and amortization


(134,972
)


(96,564
)Property, plant and equipment, net

$
823,574


$
694,727   Asset retirement obligations.
    ARO liability balance, December 31, 2006

$
340AROs incurred in 2007


188Accretion for conditional obligations


27ARO liability balance, December 31, 2007


555ARO incurred in 2008


78Accretion for conditional obligations


40ARO liability balance, December 31, 2008

$
673      F-19




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 6 
    Investment
    in Unconsolidated Affiliates      Webb
    Duval
      Year Ended December 31,2008


2007


2006Operating revenue

$
4,064


$
3,802


$
5,961Operating expenses


(2,225
)


(826
)


(3,733
)Depreciation


(779
)


(768
)


(743
)Net income


1,060



2,208



1,485Ownership %


62.5
%


62.5
%


62.5
%663



1,380



928Copanos share of management fee charged


135



132



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


21



21



21Equity in earnings from unconsolidated affiliate

$
819


$
1,533


$
1,069Distributions from unconsolidated affiliate

$
1,359


$
2,401


$
Current assets

$
1,708


$
1,920


$
4,595Noncurrent assets


6,909



7,426



8,104Current liabilities


(1,161
)


(779
)


(2,502
)Noncurrent liabilities


(55
)


(51
)


(47
)Net assets

$
7,401


$
8,516


$
10,150  F-20




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment
    in Unconsolidated Affiliates (Continued)  Southern
    Dome
      Year Ended December 31,2008


2007


2006Operating revenue

$
29,715


$
16,198


$
6,105Operating expenses


(24,483
)


(13,683
)


(5,468
)Depreciation


(744
)


(736
)


(497
)Net income


4,488



1,779



140Ownership
    %(1)


69.5
%


69.5
%


69.5
%3,119



1,236



97Copanos share of management fee charged


174



173



137Amortization of difference between the carried investment and
    the underlying equity in net assets


(10
)


(9
)


(6
)Equity in earnings from unconsolidated affiliate

$
3,283


$
1,400


$
228Distributions from unconsolidated affiliate

$
3,579


$
1,981


$
Current assets

$
2,371


$
4,434


$
2,516Noncurrent assets


16,367



16,802



17,507Current liabilities


(2,637
)


(4,473
)


(2,189
)Net assets

$
16,101


$
16,763


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




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 6 
    Investment
    in Unconsolidated Affiliates (Continued)      Year EndedDecember 31, 2008Bighorn


Fort UnionOperating revenue

$
34,854


$
52,494Operating expenses


(13,368
)


(4,397
)Depreciation


(5,171
)


(6,000
)Interest expense and other


78



(8,441
)Net income


16,393



33,656Ownership %


51
%


37.04
%8,360



12,466Priority allocation of earnings and other


519



225Copanos share of management fee charged


241



35Amortization of difference between the carried investment and
    the underlying equity in net assets


(12,704
)


(6,423
)Equity in (loss) earnings from unconsolidated affiliates

$
(3,584
)

$
6,303Distributions from unconsolidated affiliates

$
11,026


$
9,704Current assets

$
10,942


$
14,181Noncurrent assets


97,720



215,999Current liabilities


(3,395
)


(18,978
)Noncurrent liabilities






(105,097
)Net assets

$
105,267


$
106,105   F-22




---



##### Table of Contents



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


58



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


(2,995
)


(1,606
)Equity in (loss) earnings from unconsolidated affiliates

$
(819
)

$
692Distributions from unconsolidated affiliates

$
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 31,2008


2007Long-term debt:Credit Facility

$
220,000


$
280,000Senior Notes:8.125% senior unsecured notes due 2016


332,665



350,000Unamortized bond premium


704



7737.75% senior unsecured notes due 2018


267,750



Total Senior Notes


601,119



350,773Total

$
821,119


$
630,773   Senior
    Secured Revolving Credit Facility
   F-23




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
            
    a minimum EBITDA to interest expense ratio (using four
    quarters EBITDA as defined under the Credit Facility) of
    2.5 to 1.0;
    a maximum total debt to EBITDA ratio of 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).     F-24




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
    
    failure to pay any principal when due, or, within specified
    grace periods, any interest, fees or other amounts;
    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;
    our inability to demonstrate compliance with financial covenants
    within a specified period after Bighorn or Fort Union is
    prohibited from making a distribution to its members;
    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
  8.125% Senior Notes Due 2016.
      7.75% Senior Notes Due 2018.
   F-25




---



##### Table of Contents



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




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 7 
    Long-Term
    Debt (Continued)  CONDENSED
    CONSOLIDATING BALANCE SHEETS
  December 31, 2008


December 31, 2007Investment 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

$
20,417


$



$
43,267


$



$



$
63,684


$
10,018


$



$
62,647


$



$



$
72,665Accounts receivable, net


1







96,027











96,028



476







127,058











127,534Intercompany receivable


110,551







(110,551
)














37,027







(37,027
)










Risk management assets










76,440











76,440











3,289











3,289Prepayments and other current assets


911







4,093











5,004



877







3,004











3,881Total current assets


131,880







109,276











241,156



48,398







158,971











207,369Property, plant and equipment, net


136







823,438











823,574



264







694,463











694,727Intangible assets, net










198,974











198,974











200,546











200,546Investment in unconsolidated affiliates










640,598



640,598



(640,598
)


640,598











632,725



632,725



(632,725
)


632,725Investment in consolidated subsidiaries


1,723,814















(1,723,814
)






1,473,187















(1,473,187
)


Escrow Cash










1,858











1,858























Risk management assets










82,892











82,892











10,598











10,598Other assets, net


19,809







4,804











24,613



17,589







5,529











23,118Total assets

$
1,875,639


$



$
1,861,840


$
640,598


$
(2,364,412
)

$
2,013,665


$
1,539,438


$



$
1,702,832


$
632,725


$
(2,105,912
)

$
1,769,083LIABILITIES AND MEMBERS/PARTNERS CAPITALCurrent liabilities:Accounts payable

$
2


$



$
103,847


$



$



$
103,849


$
35


$



$
147,011


$



$



$
147,046Accrued interest


11,878







26











11,904



11,319



















11,319Accrued tax liability


784



















784



483







3,436











3,919Risk management liabilities










6,272











6,272











27,710











27,710Other current liabilities


1,731







15,056











16,787



882







12,049











12,931Total current liabilities


14,395







125,201











139,596



12,719







190,206











202,925Long-term debt


821,119



















821,119



630,773



















630,773Deferred tax provision


1,718



















1,718



1,231



















1,231Risk management and other noncurrent liabilities


449







12,825











13,274



579







39,439











40,018Members/Partners capital:Common units


865,343



















865,343



661,585



















661,585Class C units


13,497



















13,497



40,492



















40,492Class D units


112,454



















112,454



112,454



















112,454Class E units


























175,634



















175,634Paid-in capital


33,734



1



1,544,237



629,359



(2,173,597
)


33,734



23,773



1



1,507,285



628,375



(2,135,661
)


23,773Accumulated (deficit) earnings


(54,696
)


(1
)


111,951



11,239



(123,189
)


(54,696
)


(7,867
)


(1
)


77,837



4,350



(82,186
)


(7,867
)Other comprehensive loss


67,626







67,626







(67,626
)


67,626



(111,935
)






(111,935
)






111,935



(111,935
)1,037,958







1,723,814



640,598



(2,364,412
)


1,037,958



894,136







1,473,187



632,725



(2,105,912
)


894,136Total liabilities and members/partners capital

$
1,875,639


$



$
1,861,840


$
640,598


$
(2,364,412
)

$
2,013,665


$
1,539,438


$



$
1,702,832


$
632,725


$
(2,105,912
)

$
1,769,083  F-27




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 7 
    Long-Term
    Debt (Continued)  CONDENSED
    CONSOLIDATING STATEMENTS OF OPERATIONS
  Year Ended December 31, 2008


Year Ended December 31, 2007Investment 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

$



$



$
747,258


$



$



$
747,258


$



$



$
518,431


$



$



$
518,431Natural gas liquids sales










597,986











597,986











491,432











491,432Crude oil sales










174,667











174,667











77,142











77,142Transportation, compression and processing fees










59,006











59,006











22,306











22,306Condensate and other










50,169











50,169











32,349











32,349Total revenue










1,629,086











1,629,086











1,141,660











1,141,660Costs and expenses:Cost of natural gas and natural gas liquids










1,178,304











1,178,304











853,964











853,964Cost of crude oil purchases










171,401











171,401











74,814











74,814Transportation










21,971











21,971











5,948











5,948Operations and maintenance


948







53,613











54,561



1,764







39,392











41,156Depreciation and amortization


44







53,110











53,154



34







39,933











39,967General and administrative


25,610







19,961











45,571



10,848







23,790











34,638Taxes other than income










3,019











3,019











2,637











2,637Equity in earnings from unconsolidated affiliates










(6,889
)


(6,889
)


6,889



(6,889
)










(2,850
)


(2,850
)


2,850



(2,850
)Total costs and expenses


26,602







1,494,490



(6,889
)


6,889



1,521,092



12,646







1,037,628



(2,850
)


2,850



1,050,274Operating (loss) income


(26,602
)






134,596



6,889



(6,889
)


107,994



(12,646
)






104,032



2,850



(2,850
)


91,386Other income (expense):Interest and other income


47







1,127











1,174



247







2,607











2,854Gain on retirement of unsecured debt


15,272



















15,272























Interest and other financing costs


(53,172
)






(11,806
)










(64,978
)


(29,467
)






116











(29,351
)(Loss) income before income taxes and equity in earnings from
    consolidated subsidiaries


(64,455
)






123,917



6,889



(6,889
)


59,462



(41,866
)






106,755



2,850



(2,850
)


64,889Provision for income taxes


(1,249
)


















(1,249
)


(1,714
)


















(1,714
)(Loss) income before income taxes and equity in earnings from
    consolidated subsidiaries


(65,704
)






123,917



6,889



(6,889
)


58,213



(43,580
)






106,755



2,850



(2,850
)


63,175Equity in earnings from consolidated subsidiaries


123,917















(123,917
)






106,755















(106,755
)


Net income (loss)

$
58,213


$



$
123,917


$
6,889


$
(130,806
)

$
58,213


$
63,175


$



$
106,755


$
2,850


$
(109,605
)

$
63,175  F-28




---



##### Table of Contents



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


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Revenue:Natural gas sales

$



$



$
448,054


$



$



$
448,054Natural gas liquids sales










369,892











369,892Transportation, compression and processing fees










16,232











16,232Other










26,094











26,094Total revenue










860,272











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










669,158











669,158Transportation










3,026











3,026Operations and maintenance


917







31,567











32,484Depreciation and amortization


66







31,927











31,993General and administrative


9,296



1



17,238











26,535Taxes other than income










2,061











2,061Equity in earnings from unconsolidated affiliates










(1,297
)


(1,297
)


1,297



(1,297
)Total costs and expenses


10,279



1



753,680



(1,297
)


1,297



763,960Operating (loss) income


(10,279
)


(1
)


106,592



1,297



(1,297
)


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










1,706











1,706Interest and other financing costs


(33,207
)






303











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


(43,486
)


(1
)


108,601



1,297



(1,297
)


65,114Equity in earnings from consolidated subsidiaries


108,600















(108,600
)


Net income (loss)

$
65,114


$
(1
)

$
108,601


$
1,297


$
(109,897
)

$
65,114  F-29




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 7 
    Long-Term
    Debt (Continued)  CONDENSED
    CONSOLIDATING STATEMENTS OF CASH FLOWS
  Year Ended December 31, 2008


Year Ended December 31, 2007Investment 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

$
(155,565
)

$



$
245,489


$
22,460


$
(22,460
)

$
89,924


$
(19,109
)

$



$
147,327


$
3,706


$
(3,706
)

$
128,218Cash Flows From Investing Activities:Net cash (used in) provided by investing activities


66,010







(198,855
)


(23,463
)


(42,547
)


(198,855
)


(605,668
)






(727,052
)


(1,051
)


606,719



(727,052
)Cash Flows From Financing Activities:Net cash provided by (used in) financing activities


99,954







(66,014
)


26,833



39,177



99,950



633,509







604,174



1,727



(607,395
)


632,015Net increase (decrease) in cash and cash equivalents


10,399







(19,380
)


25,830



(25,830
)


(8,981
)


8,732







24,449



4,382



(4,382
)


33,181Cash and cash equivalents, beginning of year


10,018







62,647



4,382



(4,382
)


72,665



1,286







38,198











39,484Cash and cash equivalents, end of year

$
20,417


$



$
43,267


$
30,212


$
(30,212
)

$
63,684


$
10,018


$



$
62,647


$
4,382


$
(4,382
)

$
72,665  F-30




---



##### Table of Contents



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


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


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

$
(55,791
)

$
(1
)

$
147,471


$



$



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


61,269







(70,700
)


(10,438
)


(50,422
)


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


(5,359
)






(62,702
)


10,438



50,422



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


119



(1
)


14,069











14,187Cash and cash equivalents, beginning of year


1,167



1



24,129











25,297Cash and cash equivalents, end of year

$
1,286


$



$
38,198


$



$



$
39,484  F-31




---



##### Table of Contents



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

Amount2009

$
2010


2011


2012


220,0002013


Thereafter


600,415$
820,415    Note 8 
    Members
    Capital  Common
    Units
    Form S-3/ASR,
  Class C
    Units
   F-32




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)  12-month, 18-month 24-month
    Form S-3/ASR,
  Class D
    Units
      Class E
    Units
   F-33




---



##### Table of Contents



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

2008


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







October 1, 2007 through December 31, 2007


4,103











    F-34




---



##### Table of Contents



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

Per unit


Date Declared


Record Date


Payment Date


AmountDecember 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(a)


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



24,336,000March 31, 2008


0.5300



April 16, 2008



May 1, 2008



May 15, 2008



25,506,000June 30, 2008


0.5600



July 16, 2008



August 1, 2008



August 14, 2008



27,242,000September 30, 2008


0.5700



October 15, 2008



November 3, 2008



November 14, 2008



27,969,000December 31, 2008


0.5750



January 14, 2009



February 2, 2009



February 13, 2009



31,466,000     (a)
    
    Common units issued on October 19, 2007 were not eligible
    for this distribution pursuant to the provisions of the unit
    purchase agreement between us and the Class E unit
    purchasers.  Accounting
    for Equity-Based Compensation
  Restricted Common Units,
    Phantom Units Unit Options
  Restricted Common Units.
   F-35




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)    2008


2007


2006Weighted





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


241,181


$
22.92



315,936


$
20.84



278,236


$
18.30Granted


18,000



12.61



23,500



37.20



120,540



24.51Vested


(89,122
)


21.94



(93,742
)


19.56



(69,306
)


17.38Vested-non released


395



20.25















Forfeited


(685
)


20.95



(4,513
)


21.09



(13,534
)


19.01Outstanding at end of period


169,769


$
22.35



241,181


$
22.92



315,936


$
20.84       Phantom Units.
     F-36




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)      2008


2007Weighted





WeightedNumber of


Average


Number of


AveragePhantom


Grant-Date


Phantom


Grant-DateUnits


Fair Value


Units


Fair ValueOutstanding at beginning of year


100,795


$
40.81






$
Granted


532,248



32.40



101,465



40.82Vested


(39,477
)


26.55







Vested-non released


450



38.78







Forfeited


(5,106
)


38.06



(670
)


41.74Outstanding at end of period


588,910



34.18



100,795


$
40.81     Unit Options.
 F-37




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)    2008


2007


2006Number 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


1,442,847


$
22.60



1,212,506


$
17.15



982,220


$
15.09Granted


191,500



32.05



418,200



37.60



315,490



23.52Exercised


(71,722
)


15.74



(115,288
)


15.72



(30,064
)


12.58Cancelled


(37,040
)


14.79















Forfeited


(114,579
)


30.62



(72,571
)


29.92



(55,140
)


18.01Outstanding at end of period


1,411,006


$
23.78



1,442,847


$
22.60



1,212,506


$
17.15Aggregate intrinsic value at end of period

$
453,000






$
19,843,000






$
15,337,000Weighted average remaining contractual term


7.4 years







8.1 years







8.6 yearsExercisable Options:Outstanding at end of period


556,866


$
18.60



362,645


$
15.43



236,268


$
13.81Aggregate intrinsic value at end of period

$
329,000






$
7,585,000






$
3,779,000Weighted average remaining contractual term


6.7 years







7.5 years







8.2 yearsWeighted average fair value of option granted





$
3.00






$
4.33






$
3.10Options expected to vest:At end of period


1,269,905


$
23.78



1,298,562


$
22.60



1,091,256


$
17.15Aggregate intrinsic value at end of period


408,000






$
17,859,000






$
13,803,000Weighted average remaining contractual term


7.4 years







8.1 years







8.6 years       F-38




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)  Year Ended December 31,2008


2007


2006Weighted average exercise price

$
32.05


$
37.60


$
23.52Expected volatility


20.0-20.7
%


20.6-21.5
%


21.3-22.5
%Distribution yield


6.18-6.59
%


6.00-6.10
%


5.97-6.04
%Risk-free interest rate


1.76-3.94
%


3.48-5.11
%


4.33-5.14
%Expected term (in years)


6.5



6.5



6.5Weighted average grant-date fair value of options granted

$
3.00


$
4.33


$
3.10Total intrinsic value of options exercised

$
1,117,000


$
2,361,000


$
412,000       Liability Awards. Accounting for Certain Financial Instruments With
    Characteristics of Both Liabilities and Equity,
    2008WeightedNumber of


AveragePhantom


Grant-DateUnits


Fair ValueOutstanding at beginning of year

$



$
Granted


25,639



21.04Forfeited






Vested


(25,639
)


21.04Outstanding at end of year

$



$
   F-39




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 9 
    Related
    Party Transactions  Operations
    Services
     F-40




---



##### Table of Contents



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 31,2008


2007


2006Affiliates of Mr. Eckel:Natural gas
    sales(1)

$
113


$
31


$
97Gathering and compression
    services(2)


22



30



32Natural gas
    purchases(3)


1,426



2,251



1,808Webb Duval:Natural gas
    sales(1)


590







706Natural gas
    purchases(3)


2,542



955



1,695Transportation
    costs(4)


379



357



358Southern Dome:Natural gas liquid
    sales(5)






302



Condensate
    sales(6)






145



Bighorn:(7)Gathering
    costs(4)


603



166



Natural gas
    purchases(3)


30







Fort Union:(7)Gathering
    costs(4)


8,440



2,110Treating
    costs(3)


856



125



Other:(8)Natural gas
    sales(1)


423



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)
    
    The results for 2007 include the period from October 1,
    2007 through December 31, 2007.(8)
    
    The results for 2007 include the period from May 1, 2007
    through December 31, 2007.     F-41




---



##### Table of Contents



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

Segment


2008


2007


2006Enterprise Products Operating, L.P.


Texas



14
%


20
%


19
%ONEOK Energy Services, L.P.


Oklahoma



16
%


16
%


21
%ONEOK Hydrocarbon, L.P.


Oklahoma



13
%


14
%


13
%KMTP


Texas



9
%


10
%


14
%  F-42




---



##### Table of Contents



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

Segment


2008


2007


2006New Dominion LLC


Oklahoma



13
%


18
%


19
%Altex Resources, Inc.


Oklahoma











5
%   Percentage
    of Consolidated Accounts
    Receivable(1)
  Year Ended December 31,Customer or Counterparty

Segment


2008


2007


2006ONEOK Energy Services, L.P.


Oklahoma



15
%


18
%


25
%ONEOK Hydrocarbon, L.P.


Oklahoma







13
%


13
%Enterprise Products Operating, L.P.


Texas







10
%


11
%KMTP


Texas



11
%


8
%


12
%The Goldman Sachs Group, 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-43




---



##### Table of Contents



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




---



##### Table of Contents



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-45




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)  Adoption
    of SFAS No. 157
    
    Level 1  Unadjusted quoted prices in active
    markets that are accessible at the measurement date for
    identical, unrestricted assets or liabilities;
    Level 2  Quoted prices in markets that are not
    considered to be active or financial instruments for which all
    significant inputs are observable, either directly or indirectly;
    Level 3  Prices or valuations that require
    inputs that are both significant to the fair value measurement
    and unobservable. These inputs may be used with internally
    developed methodologies that result in managements best
    estimate of fair value.      Fair Value Measurements on aRecurring Basis December 31, 2008Level 1


Level 2


Level 3


Total(In thousands)Assets:Commodity derivatives

$



$



$
159,332


$
159,332Other derivatives














Total

$



$



$
159,332


$
159,332Liabilities:Commodity derivatives

$



$



$
(6,655
)

$
(6,655
)Other derivatives






(11,106
)






(11,106
)Total

$



$
(11,106
)

$
(6,655
)

$
(17,761
)    F-46




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)      Three MonthsEnded


Year EndedDecember 31,


December 31,2008


2008Balance, beginning of period

$
17,045


$
(48,194
)Total gains or losses:Included in earnings


2,107



(3,308
)Included in accumulated other comprehensive loss


141,885



177,136Purchases, issuances and settlements


(8,360
)


27,043Transfers in and/or out of Level 3






Balance, end of period

$
152,677


$
152,677Change in unrealized losses relating to instruments still held
    as of December 31, 2008

$
3,030


$
(2,760
)     and/or
  Note 12 
    Fair
    Value of Financial Instruments    December 31,2008


2007Carrying


Estimated


Carrying


EstimatedValue


Fair Value


Value


Fair Value(In thousands)Cash and cash equivalents

$
63,684


$
63,684


$
72,665


$
72,665Credit Facility


220,000



220,000



280,000



280,0002016 Notes


332,665



226,212



350,773



352,6252018 Notes


267,750



170,021







   F-47




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 13 
    Commitments
    and Contingencies  Commitments
  2009 2010 2011 2012 2013
           F-48




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 13 
    Commitments
    and Contingencies (Continued)  Regulatory
    Compliance
    Litigation
        Definitive
    Purchase Agreement
  McMullen Lateral Acquisition. 151-mile, 24-inch 09-38-000).
 F-49




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 13 
    Commitments
    and Contingencies (Continued)    Note 14 
    Supplemental
    Disclosures to the Statements of Cash Flows  Year Ended December 31,2008


2007


2006Cash payments for interest, net of $3,471,000, $932,000 and
    $693,000 capitalized in 2008, 2007 and 2006, respectively

$
49,205


$
24,471


$
26,884Cash payments for federal and state income taxes

$
492


$



$
     Note 15 
    Segment
    Information    
    Oklahoma, which includes natural gas midstream services in
    central and east Oklahoma, including natural gas gathering and
    related services, natural gas processing and a crude oil
    pipeline located in south Oklahoma and north Texas. Our Oklahoma
    segment includes certain assets acquired in the Cimmarron
    Acquisition and our equity investment in Southern Dome.
    Texas, which provides natural gas gathering and transmission and
    related services and natural gas processing, treating,
    conditioning, NGL fractionation and related NGL transportation
    operations in Texas and Louisiana. Our Texas segment includes
    certain assets acquired in the Cimmarron Acquisition, our
    Louisiana processing assets acquired in the Cantera Acquisition
    and our equity investment in Webb Duval.  
    Rocky Mountains, which includes natural gas gathering and
    related operations in Wyoming, was acquired through the Cantera
    Acquisition. Our Rocky Mountains segment includes our equity
    investments in Bighorn and Fort Union, two firm gathering
    agreements with Fort Union and three firm transportation
    agreements with WIC.     F-50




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##### Table of Contents



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, 2008:Total segment gross margin

$
136,378


$
142,723


$
5,877


$
284,978


$
(27,568
)

$
257,410Operations and maintenance expenses


24,611



29,950







54,561







54,561Depreciation, amortization and impairment


30,598



15,770



5,521



51,889



1,265



53,154General and administrative expenses


7,832



9,473



2,445



19,750



25,821



45,571Taxes and other income


1,683



1,336







3,019







3,019Equity in earnings from unconsolidated affiliates


(3,283
)


(888
)


(2,718
)


(6,889
)






(6,889
)Operating income

$
74,937


$
87,082


$
629


$
162,648


$
(54,654
)

$
107,994Sales to external customers

$
842,208


$
767,842


$
46,604


$
1,656,654


$
(27,568
)

$
1,629,086Intersegment sales


(1,991
)


1,991















Interest and other financing costs


















64,978



64,978Net income (loss)


75,444



87,536



753



163,733



(105,520
)


58,213Segment assets


727,875



397,788



711,434



1,837,097



176,568



2,013,665 F-51




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##### Table of Contents



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:Total segment gross margin

$
115,099


$
121,935


$
1,145


$
238,179


$
(31,245
)

$
206,934Operations and maintenance expenses


20,711



20,437



8



41,156







41,156Depreciation, amortization and impairment


25,724



12,749



670



39,143



824



39,967General and administrative expenses


5,992



16,323



597



22,912



11,726



34,638Taxes and other income


1,551



1,086







2,637







2,637Equity in (earnings) loss from unconsolidated affiliates


(1,400
)


(1,576
)


126



(2,850
)






(2,850
)Operating income

$
62,521


$
72,916


$
(256
)

$
135,181


$
(43,795
)

$
91,386Sales 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



29,351Net 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:Total segment gross margin

$
95,614


$
91,121


$



$
186,735


$
1,353


$
188,088Operations and maintenance expenses


17,185



15,299







32,484







32,484Depreciation, amortization and impairment


23,054



8,452







31,506



487



31,993General and administrative expenses


4,560



12,213







16,773



9,762



26,535Taxes and other income


1,118



943







2,061







2,061Equity in earnings from unconsolidated affiliates


(91
)


(1,206
)






(1,297
)






(1,297
)Operating income

$
49,788


$
55,420


$



$
105,208


$
(8,896
)

$
96,312Sales to external customers

$
411,196


$
447,723


$



$
858,919


$
1,353


$
860,272Interest and other financing costs






2







2



32,902



32,904Net income (loss)


50,749



56,098







106,847



(41,733
)


65,114    Note 16 
    Quarterly
    Financial Data (Unaudited)  Year 2008Quarter EndedMarch 31


June 30


September 30


December 31


Year(In thousands, except per unit information)Revenue

$
401,748


$
501,278


$
453,633


$
272,427


$
1,629,086Operating income


25,722



39,366



24,033



18,873



107,994Net income


14,502



23,202



8,723



11,786



58,213Basic net income per common unit


0.31



0.49



0.18



0.23



1.20Diluted net income per common unit


0.25



0.40



0.15



0.21



1.01   F-52




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 16 
    Quarterly
    Financial Data (Unaudited) (Continued)  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     (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 2008 as a result of the Cimmarron
    Acquisition in May 2007 and the Cantera Acquisition in October
    2007. F-53




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##### Table of Contents



INDEPENDENT
    AUDITORS REPORT          
    F-54




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  BALANCE SHEET
  December 31,2008


2007(Unaudited)ASSETSCurrent assets:Cash and cash equivalents

$
6,761,393


$
3,660,296Accounts receivable:Trade


3,935,774



3,203,418Related parties


44,810



Prepaid expenses and other


200,498



116,957Total current assets


10,942,475



6,980,671Property and equipment, net


97,523,222



97,327,215Intangible assets, net


196,369



243,138$
108,662,066


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

$
761,734


$
1,431,940Related parties


2,108,853



323,054Accrued liabilities


523,927



167,905Total current liabilities


3,394,514



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


105,267,552



102,628,125Total liabilities and members equity

$
108,662,066


$
104,551,024    F-55




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  STATEMENT OF OPERATIONS
  Period fromYear Ended


October 1 2007, toDecember 31,


December 31,2008


2007(Unaudited)Gathering fee revenue

$
34,853,731


$
7,809,074Expenses:Operating
    expenses(1)


12,915,555



2,605,066General and administrative


452,896



81,836Depreciation and amortization


5,171,048



994,432Total expenses


18,539,499



3,681,334Operating income


16,314,232



4,127,740Other income:Interest income


77,984



24,367Other expense






(309
)Total other income


77,984



24,058Net income

$
16,392,216


$
4,151,798   (1)
    
    Exclusive of depreciation and amortization shown separately
    below.   F-56




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##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  STATEMENT OF CASH FLOWS
  Period fromYear Ended


October 1 2007, toDecember 31,


December 31,2008


2007(Unaudited)Cash flow from operating activities:Net income

$
16,392,216


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


5,171,048



994,432Changes in assets and liabilities:Accounts receivable


(777,166
)


269,988Prepaid expenses and other


(83,541
)


53,232Accounts payable


1,115,593



(524,106
)Accrued liabilities


356,022



81,150Net cash provided by operating activities


22,174,172



5,026,494Cash flow from investing activities:Additions to property, plant and equipment


(5,172,436
)


(4,117,405
)Additions to intangible assets


(147,850
)


Net cash used in investing activities


(5,320,286
)


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


(1,901,500
)


(583,932
)Distributions to members


(18,700,000
)


(4,000,000
)Equity contributions from members


6,848,711



2,896,501Net cash used in financing activities


(13,752,789
)


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


3,101,097



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


3,660,296



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

$
6,761,393


$
3,660,296    F-57




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##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  STATEMENT
    OF MEMBERS EQUITY  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


$
102,628,125Contributions (unaudited)


6,586,200



209,325



53,186



6,848,711Allocation of 2008 contributions (unaudited)


(3,093,358
)


2,461,678



631,680



Distributions (unaudited)


(11,438,500
)


(7,293,000
)


(1,870,000
)


(20,601,500
)Net income (unaudited)


9,291,766



5,651,378



1,449,072



16,392,216Balance at December 31, 2008(unaudited)

$
53,686,452


$
41,054,345


$
10,526,755


$
105,267,552    F-58




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS
  Note 1 
    Organization
    and Business    Copano Pipelines/Rocky Mountains, LLC (Copano)


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
   F-59




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)  Gas
    Gathering Operations
    Cash
    and Cash Equivalents
    Imbalances
    Property
    and Equipment
    December 31,Useful Lives


2008


2007(Unaudited)Vehicles


3 Years


$
1,108,673


$
922,866Computer and communication equipment


5 Years



554,816



511,341Pipeline materials


N/A



20,244



26,243Construction in progress


N/A



2,204,192



Gathering lines and related equipment


30 Years



122,702,696



120,550,468126,590,621



122,010,918Less accumulated depreciation






(29,067,399
)


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





$
97,523,222


$
97,327,215   Intangible
    assets
   F-60




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS  (Continued)
   Note 2 
    Summary
    of Significant Accounting Policies (Continued)    December 31,2008


2007(Unaudited)Rights-of-way , at cost

$
493,146


$
345,296Less accumulated amortization for rights-of-way and easements


(296,777
)


(102,158
)Intangible assets, net

$
196,369


$
243,138   Asset
    Impairment
    Fair
    Value of Financial Instruments
    Concentration
    of Credit Risk
        Income
    Taxes
   F-61




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS  (Continued)
  Note 3 
    New
    Accounting Pronouncements  Fair
    Value Measurements
  Fair
    Value Measurements. Accounting for Derivative
    Instruments and Hedging Activities,
  No. SFAS 157-2, Effective Date of FASB Statement No. 157,
  Fair
    Value Option for Financial Assets and Financial
    Liabilities
  The Fair Value Option for Financial Assets and
    Financial Liabilities,
  Useful
    Life of Intangible Assets
  No. 142-3, Determination of the Useful Life of Intangible
    Assets, Goodwill and Other
    Intangible Assets. No. 142-3
  Note 4 
    Operating
    Leases    Year Ending December 31,2009

$
1,023,8022010


190,886$
1,214,688  F-62




---



##### Table of Contents



BIGHORN
    GAS GATHERING, L.L.C.
  NOTES TO FINANCIAL STATEMENTS  (Continued)
   Note 4 
    Operating
    Leases (Continued)    Note 5 
    Related-Party
    Transactions          Note 6 
    Commitments
    and Contingencies   F-63




---



##### Table of Contents



EXHIBIT
    INDEX
  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).4
.7

Indenture, dated May 16, 2008, among Copano Energy, L.L.C.,
    Copano Energy Finance Corporation, the Subsidiary Guarantors
    named therein and U.S. Bank National Association, as trustee
    (incorporated by reference to Exhibit 4.1 to Current Report
    on
    Form 8-K
    filed May 19, 2008).4
.8

Form of Global Note representing 7.75% Senior Notes due
    2018 (included in 144A/Regulation S Appendix to
    Exhibit 4.7 above).4
.9

Registration Rights Agreement, dated May 16, 2008, among
    Copano Energy, L.L.C., Copano Energy Finance Corporation, the
    Subsidiary Guarantors named therein and the Initial Purchasers
    named therein (incorporated by reference to Exhibit 4.2 to
    Current Report on
    Form 8-K
    filed May 19, 2008).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).10
.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).




---



##### Table of Contents



Number

Description10
.4

Third Amendment to Copano Energy, L.L.C. Long-Term Incentive
    Plan, dated November 18, 2008 (incorporated by reference to
    Exhibit 99.1 to Current Report on
    Form 8-K
    filed November 25, 2008).10
.5

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
.6

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
.7

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
.8

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
.9

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
.10

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
.11

Third Amendment to Employment Agreement between CPNO Services,
    L.P., R. Bruce Northcutt and the Copano Controlling Entities,
    effective November 18, 2008 (incorporated by reference to
    Exhibit 99.2 to Annual Report on
    Form 10-K
    filed November 25, 2008).10
.12

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
.13

First Amendment to Employment Agreement between CPNO Services,
    L.P. and John A. Raber effective November 19, 2008
    (incorporated by reference to Exhibit 99.2 to Annual Report
    on
    Form 10-K
    filed November 25, 2008).10
.14

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
.15*

First Amendment to Employment Agreement between ScissorTail
    Energy, L.L.C. and Sharon Robinson dated as of December 31,
    2008.10
.16

Retirement, Release and Consulting Services Agreement, dated
    May 15, 2008, between Copano Energy, L.L.C. and Ronald W.
    Bopp (incorporated by reference to Exhibit 10.5 to
    Quarterly Report on
    Form 10-Q
    filed August 8, 2008).10
.17

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
.18

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
.19

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
.20

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
.21

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).10
.22

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
.23

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
.24

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).




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##### Table of Contents



Number

Description10
.25

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
.26

November 2006 Form of Restricted Unit Grant (Directors)
    (incorporated by reference to Exhibit 10.1 to Current
    Report on
    Form 8-K
    filed November 20, 2006).10
.27

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
.28

2008 Form of Phantom Unit Grant (Employees) (incorporated by
    reference to Exhibit 10.1 to Current Report on
    Form 8-K
    filed June 6, 2008).10
.29

2008 Form of Performance Based Phantom Unit Grant (Employees)
    (incorporated by reference to Exhibit 10.2 to Current
    Report on
    Form 8-K
    filed June 6, 2008).10
.30

2008 Form of Long-Term Retention Award Grant (Employees)
    (incorporated by reference to Exhibit 10.3 to Current
    Report on
    Form 8-K
    filed June 6, 2008).10
.31

2008 Form of Phantom Unit Grant (Employee Bonus Awards)
    (incorporated by reference to Exhibit 99.2 to Current
    Report on
    Form 8-K
    filed November 12, 2008).10
.32

2008 Form of Restricted Unit Grant (Directors) (incorporated by
    reference to Exhibit 99.4 to Current Report on
    Form 8-K
    filed November 25 2008).10
.33

Copano Energy, L.L.C. Management Incentive Compensation Plan
    (incorporated by reference to Exhibit 99.1 to Current
    Report on
    Form 8-K
    filed November 12, 2008).10
.34

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
.35

Copano Energy, L.L.C. Deferred Compensation Plan dated
    December 16, 2008 (incorporated by reference to
    Exhibit 99.1 to Current Report on
    Form 8-K
    filed December 19, 2008).10
.36

Form of Deferred Compensation Plan Participation Agreement
    (incorporated by reference to Exhibit 99.2 to Current
    Report on
    Form 8-K
    filed December 19, 2008).10
.37

Form of Deferred Compensation Plan Chief Executive Officer
    Participation Agreement (incorporated by reference to
    Exhibit 99.3 to Current Report on
    Form 8-K
    filed December 19, 2008).10
.38

Form of Indemnification Agreement (incorporated by reference to
    Exhibit 10.1 to Current Report on
    Form 8-K
    filed November 2, 2005).10
.39

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
.40

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
.41

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
.42

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
.43

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
.44

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
.45

First Amendment to Amended and Restated Credit Agreement, dated
    October 19, 2007. (incorporated by reference to
    Exhibit 10.40 to Annual Report on
    Form 10-K
    filed February 29, 2008)10
.46

Purchase Agreement, dated May 13, 2008, among Copano
    Energy, L.L.C., Copano Energy Finance Corporation, the
    Subsidiary Guarantors named therein and the Initial Purchasers
    named therein (incorporated by reference to Exhibit 10.1 to
    Current Report on
    Form 8-K
    filed May 19, 2008).




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##### Table of Contents



Number

Description21
.1

List of Subsidiaries (incorporated by reference to
    Exhibit 21.1 to Annual Report on
    Form 10-K
    filed February 29, 2008).23
.1*

Consent of Deloitte & Touche LLP.31
.1*

Sarbanes-Oxley Section 302 certification of John R. Eckel,
    Jr. (Chief Executive Officer) for Copano Energy, L.L.C.31
.2*

Sarbanes-Oxley Section 302 certification of Matthew J.
    Assiff (Chief Financial Officer) for Copano Energy, L.L.C.32
.1*

Sarbanes-Oxley Section 906 certification of John R. Eckel,
    Jr. (Chief Executive Officer) for Copano Energy, L.L.C.32
.2*

Sarbanes-Oxley Section 906 certification of Matthew J.
    Assiff (Chief Financial Officer) for Copano Energy, L.L.C.     *
    
    Filed herewith.
    
    Portions of this exhibit have been omitted pursuant to a request
    for confidential treatment.