##### Table of Contents





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

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31,
    2009ORo

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 Global Select Market   SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE
    ACT:
  Title of Class
  None
  þ o
  o þ
  þ o
  Regulation S-T o 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 11, 2010

Part III




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##### 





TABLE OF
    CONTENTS
   
 PagePART IItem 1.


Business


1Item 1A.


Risk Factors


26Item 1B.


Unresolved Staff Comments


44Item 2.


Properties


44Item 3.


Legal Proceedings


44PART IIItem 5.


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


46Item 6.


Selected Financial Data


49Item 7.


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


50Item 7A.


Quantitative and Qualitative Disclosures about
    Market Risk


79Item 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-10.3EX-23.1EX-31.1EX-31.2EX-32.1EX-32.2




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PART I      /d:

Per day$/gal:

U.S. dollars per gallonBbls:

BarrelsBcf:

One billion cubic feetBtu:

One British thermal unitGPM:

Gallons per minuteLean gas:

Natural gas that is low in NGL contentMMBtu:

One million British thermal unitsMcf:

One thousand cubic feetMMcf:

One million 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 processedRich gas

Natural gas that is high in NGL contentTcf:

One trillion cubic feetThroughput:

The volume of natural gas or NGLs  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
  Expanded commodity risk management
    portfolio.
 1




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##### Table of Contents



North Texas contract.
  Declaration of distribution.
  Approved capital projects for 2010.
  Unit conversions. one-for-one
  Business
    Strategy
    
    Pursuing growth from our existing
    assets.  Where our pipelines and processing plants
    have excess capacity, we have opportunities to increase
    throughput volume and cash flow with minimal incremental costs.
    We seek to increase volumes and utilization of capacity by
    aggressively marketing our services to producers in order to
    connect new supplies of natural gas.
    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 and Saint Jo processing plants have the
    ability to condition natural gas, rather than fully process it,
    which provides us and many of our producers with significant
    benefits during periods when processing natural gas is not
    economic. Also, several of our processing plants have
    ethane-rejection capability, which we employ as market
    conditions or operating conditions warrant, and we plan to
    restart our NGL fractionation capability at our Houston Central
    plant.
    Pursuing complementary acquisitions and organic expansion in
    our operating areas.  We seek complementary
    acquisitions and capital projects that we believe will enhance
    our ability to increase cash flows from our existing assets by
    capitalizing on our existing infrastructure, personnel and
    producer and customer relationships. Also, we seek to expand our
    assets where appropriate to meet increased demand for our
    midstream services.
    Expanding into new regions where our growth strategy can be
    applied.  We plan to pursue potential acquisitions
    and significant greenfield projects in new regions to the extent
    they offer cash flow and operational growth opportunities that
    are attractive to us.
    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. 2




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Our
    Operations
    Our
    Operating Segments
  Overview
    Copano
    Energy Operating Segments
  Year EndedDecember 31, 2009Pipeline
    Miles(1)





Average/Number of


Throughput


ThroughputProcessing


/Inlet


/Inlet


UtilizationSegment

Assets

Plants


Capacity(2)(3)


Volumes(2)(3)


of CapacityOklahoma

Natural Gas Pipelines


3,766



305,100



221,846



73
%Processing
    Plants(4)


4



158,000



115,358



73
%Texas

Natural Gas
    Pipelines(5)


2,033



993,800



335,836



34
%Processing
    Plants(6)


3



950,000



491,648



52
%NGL
    Pipelines(7)


256



101,400



18,386



18
%Rocky Mountains

Natural Gas
    Pipelines(8)


591



1,550,000



1,019,094



66
%     (1)
    
    Natural gas pipeline miles for
    Oklahoma and Texas exclude 2,973 miles and 588 miles,
    respectively, of inactive pipelines that are being held for
    potential future development.(2)
    
    Capacity values generally are based
    on current operating configurations and could be increased or
    decreased through removal or addition of compression, delivery
    meter capacity or other facility modifications.(3)
    
    Natural gas pipeline throughputs
    and inlet capacity are presented in Mcf/d. 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 company in which we own a majority interest.(5)
    
    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.(6)
    
    Includes our processing plant in
    Lake Charles, Louisiana, which has limited operations.(7)
    
    Includes our
    46-mile
    Brenham NGL pipeline and
    51-mile KS
    NGL pipeline, both of which are leased.(8)
    
    Owned by Bighorn Gas Gathering,
    L.L.C. (Bighorn) and Fort Union Gas Gathering,
    L.L.C. (Fort Union), unconsolidated companies
    in which we own 51.0% and 37.04% interests, respectively. We do
    not operate Fort Union.   3




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Oklahoma
    
    nine primarily low-pressure gathering systems occupying
    approximately 53,000 square miles; and
    four processing plants, one of which we own through our majority
    interest in Southern Dome. 4




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5




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Oklahoma
    Pipelines
  Diameter of





Year Ended December 31, 2009Length


Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


of CapacityNatural Gas PipelinesStroud


874



22-
    162



124,000



109,650



88
%Milfay


364



22-
    162



15,000



11,871



79
%Glenpool


1,019



22-
    102



20,000



9,225



46
%Twin Rivers


554



22-
    122



23,000



13,811



60
%Central
    Oklahoma(3)


216



32-
    102



4,100



3,323



81
%Osage


560



22- 82



29,000



21,898



76
%Mountain(4)


179



22-
    202



90,000



52,068



58
%     (1)
    
    Capacity values generally are based
    on current operating configurations and could be increased or
    decreased through addition or removal of compression, delivery
    meter capacity or other facility modifications.(2)
    
    Natural gas pipeline throughputs
    are presented in Mcf/d.(3)
    
    Excludes 2,973 miles of
    inactive pipelines held for potential future development.(4)
    
    The Mountain system consists of
    three separate systems: Blue Mountain, Cyclone Mountain and Pine
    Mountain.  Oklahoma
    Processing
  Year Ended December 31, 2009AverageAverage

Utilization

ProcessingThroughput

Inlet

of

Volumes(1)Processing Plants

Facilities

Capacity(1)

Volumes(1)

Capacity

NGLs

ResiduePaden

Cryogenic/refrigeration Nitrogen
    rejection(3)


100,000



86,184



86
%


11,906



69,812Milfay

Propane refrigeration


15,000



9,271



62
%


701



8,256Glenpool

Cryogenic


25,000



8,716



35
%


437



8,187Southern
    Dome(2)

Propane refrigeration


18,000



11,188



62
%


472



10,452     (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)
    
    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. Throughput
    currently is limited to 18,000 Mcf/d due to inlet
    compression.(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.    Stroud
    System and Interconnected Area
  Stroud System.
  Paden Processing Plant.
 6




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Milfay System and Processing Plant.
  Glenpool System and Processing Plant.
  Twin Rivers System.
  Central Oklahoma System.
  Osage System.
  Mountain Systems.
  Crude Oil Pipeline.
  Southern Dome.
 7




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Texas
   8




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9




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Texas
    Pipelines
  Year EndedDecember 31, 2009Length


Diameter of Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(1)(2)


Throughput(1)(2)


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


1,137



22-
    202



562,800



171,320



30
%Houston Central


332



22-
    122



239,000



97,439



41
%Upper Gulf Coast


239



22-
    122



139,000



43,132



31
%North
    Texas(5)


325



32-
    122



53,000



23,945



45
%NGL Pipelines:Sheridan(6)


104



62



30,900



7,113



23
%Brenham


46



62



20,250



5,316



26
%Markham(7)


50



62



24,250



4,388



18
%KS(8)


51



62



8,000








%Saint Jo


5



62



18,000



1,569



9
%     (1)
    
    Capacity values generally are based
    on current operating configurations and could be increased or
    decreased through addition or removal of compression, delivery
    meter capacity or other facility modifications.(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 588 miles of inactive
    pipelines held for potential future development.(6)
    
    We anticipate that we will place
    the western portion of the Sheridan NGL pipeline into purity
    propane service late in the first quarter of 2010.(7)
    
    We acquired the
    50-mile
    Markham NGL pipeline in December 2008 and placed it into NGL
    transportation service in August 2009. We anticipate that we
    will place the Markham NGL pipeline into purity ethane service
    late in the first quarter of 2010.(8)
    
    We leased the KS NGL pipeline in
    January 2010. We anticipate that we will place the KS line into
    purity propane service late in the first quarter of 2010.  Texas
    Processing
  Year Ended December 31, 2009AverageAverage





ProcessingThroughput

Inlet


Utilization of


Volumes(1)Processing Plants

Facilities

Capacity(1)

Volumes(1)


Capacity


NGLs


ResidueHouston Central

Cryogenic/lean oil

700,000


462,144



66
%


15,399
(2)


427,992Saint
    Jo(3)

Cryogenic

50,000


12,577



25
%


734



17,504Lake Charles

Cryogenic

200,000


16,927
(4)


8
%


676
(4)


16,503
(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
    3,449 Bbls/d, 5,316 Bbls/d and 4,388 Bbls/d of
    ethane, propane, butane and natural gasoline mix delivered to
    the Sheridan, Brenham and Markham NGL pipelines, respectively,
    and 2,231 Bbls/d of stabilized condensate delivered to the
    Teppco crude oil pipeline.(3)
    
    The Saint Jo plant is designed for
    operating capacity of 100,000 Mcf/d but is currently
    configured for 50,000 Mcf/d.(4)
    
    Average inlet volumes and average
    processing volumes for the Lake Charles plant represent
    60 days of activity in 2009. The Lake Charles plant
    operates only when the LNG regasification facility to which it
    is connected is operating and is sending natural gas to the
    plant. 10




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South
    Texas
  South Texas Systems. Laredo-to-Katy 30-inch
        Houston Central Systems and Processing
    Plant. Laredo-to-Katy
    
    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 22,000 Bbls/d NGL fractionation facility; and
    882,000 gallons of storage capacity for propane, butane-natural
    gasoline mix and stabilized condensate.    
    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. 11




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Laredo-to-Katy
  163-acre
  Sheridan, Brenham, Markham and KS NGL
    Pipelines.
  5-year
      Our Commercial Relationship with Kinder
    Morgan. 30-inch-diameter Laredo-to-Katy
  Upper
    Gulf Coast Systems
   12




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North
    Texas Systems
    Rocky
    Mountains
    Rocky
    Mountains Pipelines and
    Services(1)
  Diameter of





Year Ended December 31, 2009Length


Pipe


Throughput


Average


Utilization(miles)


(range)


Capacity(2)


Throughput(3)


of CapacityNatural Gas
    Pipelines(1)


591



62-
    242



1,550,000



1,019,094



66
%Producer
    Services(4)














170,025



     (1)
    
    Consists of pipelines owned by
    Bighorn and Fort Union. Fort Union also has 1,500 GPM
    of amine treating capacity.(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. 13




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14




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




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Natural
    Gas Supply
          Oklahoma
   16




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Texas
    Rocky
    Mountains
      3.8 million-acre AMI
    Competition
      Oklahoma
     17




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Texas
      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 deliver
    it to larger pipelines for further transmission. 18




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
    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 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 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 19




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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.    
    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.
   20




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##### Table of Contents



and/or
  th
  FERC Regulation of NGL Pipelines.
  Intrastate Natural Gas Pipeline Regulation.
  Natural Gas Gathering
    Regulation.
      State Utility Regulation.
 21




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Sales of Natural Gas 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.
  Pipeline Safety.
 23




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Employee Health and Safety.
  Anti-terrorism Measures.
  Endangered Species.
 24




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Climate Change. cap-and-trade e.g.
    Office
    Facilities
    Employees
   25




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##### Table of Contents



Available
    Information
  1-800-SEC-0330. (http://www.sec.gov)
  (http://www.copanoenergy.com) (713-621-9547), Form 10-K, Form 10-Q, Form 8-K
  Item 1A.
    Risk
    Factors  In addition to the factors discussed elsewhere in this
    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. 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 amount of capital we spend on projects and their
    profitability;
    our ability to borrow money and access capital markets; 26




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##### Table of Contents




    the cost of any acquisitions we make;
    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;
    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.    A
    decrease in our cash flow will reduce the amount of cash we have
    available for distribution to our unitholders.
    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.
      
    the impact of weather on the demand for oil and natural gas;
    the level of domestic oil and natural gas production;
    storage levels for oil, natural gas, LNG and NGLs;
    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; 27




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##### Table of Contents




    the availability and marketing of competitive fuels;
    the impact of energy conservation efforts; and
    the extent of governmental regulation and taxation.    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 debt service
    requirements;
    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 if interest rates increase (to
    the extent that our debt is subject to variable interest rates);
    have a material adverse effect on us if we fail to comply with
    financial or other covenants in our debt agreements and an event
    of default results and 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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##### Table of Contents



Restrictive
    covenants in the agreements governing our indebtedness may
    reduce our operating flexibility.
    
    sell assets;
    pay distributions on, redeem or repurchase our equity interests
    or redeem or repurchase our subordinated debt, if any;
    make investments;
    incur or guarantee additional indebtedness or issue preferred
    units;
    create or incur certain liens;
    enter into agreements that restrict distributions or other
    payments from our restricted subsidiaries to us;
    consolidate, merge or transfer all or substantially all of our
    assets;
    engage in transactions with affiliates;
    create unrestricted subsidiaries;
    enter into sale and leaseback transactions; and
    enter into letters of credit.        Our
    ability to obtain funding under our revolving credit facility
    could be impaired by conditions in the financial
    markets.
   29




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##### Table of Contents




    one or more of our lenders failed to meet its funding
    obligations;
    at the time we draw on our revolving credit facility, any of the
    representations or warranties or certain covenants included in
    the agreement is false in any material respect and the lenders
    elected to refuse to provide funding; and
    any lender refuses to fund its commitment for any reason,
    whether or not valid, and the other lenders elect not to provide
    additional funding to make up for the unfunded portion.    Our
    ability to obtain financing from sources other than our
    revolving credit facility is subject to conditions in the credit
    and capital markets.
      We are
    exposed to the credit risk of our customers and other
    counterparties, and a general increase in nonpayment and
    nonperformance by counterparties could adversely affect our cash
    flows, results of operations and financial
    condition.
      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.
   30




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##### Table of Contents




    hedging can be expensive, particularly during periods of
    volatile prices or when hedging into extended future periods;
    our counterparty in the hedging transaction may default on its
    obligation to pay; and
    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.    The
    adoption of derivatives legislation by Congress could have an
    adverse impact on our ability to hedge risks associated with our
    business.
  over-the-counter
 31




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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.
            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 capacity-constrained or unavailable,
    our cash flows, results of operations and financial condition
    could be adversely affected.
  Laredo-to-Katy
 32




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##### Table of Contents



Laredo-to-Katy
        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 on the anticipated timetable, or at all;
    the loss of significant producers or markets or key employees
    from the acquired businesses;
    diversion of managements attention from other business
    concerns;
    failure to realize expected profitability or growth;
    failure to realize any expected synergies and cost savings;
    exposure to increased competition;
    coordinating geographically disparate organizations, systems and
    facilities; 33




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##### Table of Contents




    coordinating or consolidating information technology, compliance
    under the Sarbanes-Oxley Act of 2002 and other administrative or
    compliance functions; and
    a decrease in liquidity and increased leverage as a result of
    using significant amounts of available cash or debt to finance
    an acquisition.    Our
    acquisitions could expose us to potential significant
    liabilities.
    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.
    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.
   34




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Federal,
    state or local regulatory measures could adversely affect our
    business.
             35




---



##### Table of Contents



and/or
      Climate
    change legislation or regulations restricting emissions of
    GHG could result in increased operating costs and
    reduced demand for our services.
  cap-and-trade
 36




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##### Table of Contents



Significant
    physical effects of climatic change have the potential to damage
    our facilities, disrupt our production activities and cause us
    to incur significant costs in preparing for or responding to
    those effects.
    A
    change in the characterization of some of our assets by federal,
    state or local regulatory agencies could adversely affect our
    business.
    and/or
 37




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##### Table of Contents



We may
    incur significant costs and liabilities resulting from pipeline
    integrity programs and related repairs.
        Because
    we handle natural gas, NGLs and other hydrocarbons 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.
     38




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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.
  rights-of-way rights-of-way rights-of-way rights-of-way. rights-of-way rights-of-way
  Our
    business involves many hazards and operational risks, some of
    which may not be fully covered by insurance. If a significant
    accident or event occurs that is not fully insured, our
    operations could be temporarily or permanently impaired, and our
    liabilities and expenses could be significant.
    
    damage to pipelines, pipeline blockages and damage to related
    equipment and surrounding properties caused by hurricanes,
    tornadoes, floods, fires, extreme weather conditions and other
    natural disasters and acts of terrorism;
    inadvertent damage from motor vehicles, construction or farm
    equipment;
    leaks of natural gas, NGLs and other hydrocarbons;
    operator error; and
    fires and explosions.  and/or
   39




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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.
    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;
    majority interest in Southern Dome;
    51% interest in Bighorn; and
    37.04% interest in Fort Union    day-to-day day-to-day
  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.
   40




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##### Table of Contents



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.
    Increases
    in interest rates could adversely affect our unit
    price.
    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 federal income
    tax purposes or we were to become subject to a material amount
    of entity-level taxation for state purposes, it would
    substantially reduce the amount of cash available for
    distribution to our unitholders.
       41




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##### Table of Contents



If the
    IRS contests the federal income tax positions we take, the
    market for our common units may be adversely impacted, and the
    costs of any IRS contest will reduce cash available for
    distribution to our unitholders.
    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
 42




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##### Table of Contents



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.
    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.
   43




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##### Table of Contents



As a
    result of investing in our common units, you may be subject to
    state and local taxes and return filing requirements in states
    where you do not live.
    Item 1B.
    Unresolved
    Staff Comments    Item 2.
    Properties  rights-of-way rights-of-way right-of-way
  rights-of-way,
    Item 3.
    Legal
    Proceedings       44




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##### Table of Contents



45




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##### 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 Unit2009:Quarter Ended December 31

$
24.39


$
15.95


$
0.575Quarter Ended September 30

$
19.28


$
14.40


$
0.575Quarter Ended June 30

$
17.42


$
12.94


$
0.575Quarter Ended March 31

$
17.21


$
11.14


$
0.5752008:Quarter Ended December 31

$
24.99


$
8.80


$
0.575Quarter Ended September 30

$
34.21


$
22.25


$
0.570Quarter Ended June 30

$
39.75


$
33.00


$
0.560Quarter Ended March 31

$
37.44


$
31.29


$
0.530         Class C
    Units
   46




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##### Table of Contents



Class D
    Units
  one-for-one
  Common
    Unitholder Return Performance Presentation
   47




---



##### Table of Contents



Cumulative
    Total Unitholder Return
  
  November 9,


December 31,2004


2005


2006


2007


2008


2009Copano (CPNO)

$
100


$
180


$
288


$
367


$
127


$
289Alerian MLP Total Return Index (AMZX)

$
100


$
113


$
142


$
160


$
101


$
178S&P 500 Index (SPX)

$
100


$
107


$
122


$
126


$
78


$
96     Issuer
    Purchases of Equity Securities
    Recent
    Sales of Unregistered Securities
   48




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##### Table of Contents



Item 6.
    Selected
    Financial Data  Selected
    Historical Consolidated Financial Information
    Year Ended December 31,2009


2008


2007(1)


2006


2005(2)(In thousands, except per unit data)Summary of Operating Results:Revenue(3)

$
820,046


$
1,454,419


$
1,064,515


$
860,272


$
747,743Income from continuing operations

$
20,866


$
55,922


$
61,381


$
65,114


$
30,352Basic income per common unit from continuing
    operations(4)

$
0.39


$
1.15


$
1.44


$
1.77


$
1.20Diluted income per common unit from continuing
    operations(4)

$
0.36


$
0.97


$
1.32


$
1.75


$
1.15Other Financial Information:Cash distributions per common unit

$
2.30


$
2.17


$
1.73


$
1.29


$
0.79   As of December 31,2009


2008


2007(1)


2006


2005(2)(In thousands)Balance Sheet Information:Total assets

$
1,867,412


$
2,013,665


$
1,769,083


$
839,058


$
792,750Long-term debt


852,818



821,119



630,773



255,000



398,000Members capital


860,026



1,037,958



894,136



472,586



281,803     (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)
    
    Our summary financial data as of
    and for the years ended December 31, 2009, 2008 and 2007
    excludes the results attributable to our crude oil pipeline and
    related activities, as they are classified as discontinued
    operations. Please read Note 15  Discontinued
    Operations to the audited consolidated financial statements
    included in Item 8 of this report.(4)
    
    Net income 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. 49




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##### Table of Contents



Item 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operation    Overview
    
    Our Oklahoma segment provides midstream natural gas services in
    central and east Oklahoma, including gathering of natural gas
    and related services such as compression, dehydration, treating,
    processing and nitrogen rejection. This segment includes our
    equity investment in Southern Dome, and through September 2009,
    included a crude oil pipeline.
    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, treating, conditioning or processing
    and marketing. Our Texas segment also provides NGL fractionation
    and transportation through our Houston Central plant and our NGL
    pipelines. In addition, our Texas segment includes a processing
    plant located in southwest Louisiana and our equity investment
    in Webb Duval.
    Our Rocky Mountains segment provides midstream natural gas
    services in the Powder River Basin of Wyoming, including
    gathering and treating of natural gas. This segment also
    includes our equity investments in Bighorn and Fort Union.    Trends
    and Uncertainties
    Commodity
    Prices and Producer Activity
     50




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##### Table of Contents



Pricing Trends in Texas. First-of-the-month
    Texas
    Average Prices for Oil, Natural Gas and
    NGLs(1)
  
   (1)
    
    Average quarterly NGL prices are
    calculated based on our weighted-average product mix at Mt.
    Belvieu for the period indicated.  Annual Data for Texas:



Quarterly Data for Texas:2007


2008


2009



Q1 2009


Q2 2009


Q3 2009


Q4 2009Houston Ship Channel ($/MMBtu)

$
6.58


$
8.67


$
3.78



$
4.21


$
3.44


$
3.32


$
4.16Mt. Belvieu ($/barrel)

$
47.64


$
60.61


$
33.51



$
25.81


$
30.12


$
35.09


$
42.96NYMEX oil ($/barrel)

$
72.36


$
99.75


$
62.09



$
43.31


$
59.79


$
68.24


$
76.13Service throughput (MMBtu/d)


642,528



686,791



619,615




644,752



630,674



613,234



576,224Plant inlet (MMBtu/d)


567,073



610,249



539,633




558,115



559,597



543,994



497,368Segment gross margin (in thousands)

$
121,935


$
142,723


$
103,620



$
20,580


$
23,320


$
26,875


$
32,845   Pricing Trends in Oklahoma.
 51




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##### Table of Contents



First-of-the-month
    Oklahoma
    Average Prices for Oil, Natural Gas and
    NGLs(1)
  
   (1)
    
    Average quarterly NGL prices are
    calculated based on our weighted-average product mix at Conway
    for the period indicated. Segment gross margin results exclude
    activities attributable to our crude oil pipeline and related
    assets discussed in Note 15, Discontinued
    Operations, to our consolidated financial statements
    included in Item 8 of this report.  Annual Data for Oklahoma:



Quarterly Data for Oklahoma:2007


2008


2009



Q1 2009


Q2 2009


Q3 2009


Q4 2009CenterPoint East ($/MMBtu)

$
6.07


$
7.11


$
3.27



$
3.37


$
2.70


$
2.98


$
4.01Conway ($/barrel)

$
45.93


$
51.28


$
29.65



$
24.13


$
25.57


$
27.62


$
40.86NYMEX oil ($/barrel)

$
72.36


$
99.75


$
62.09



$
43.31


$
59.79


$
68.24


$
76.13Service throughput (MMBtu/d)


199,906



238,836



262,259




271,222



267,576



260,296



250,248Plant inlet (MMBtu/d)


144,050



156,057



163,474




160,181



166,846



166,884



159,713Segment gross margin (in thousands)

$
112,763


$
133,112


$
76,686



$
14,300


$
17,472


$
18,284


$
26,628   Basis Trends.
  Pricing Trends in the Rocky Mountains. First-of-the-month
   52




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##### Table of Contents



Rocky
    Mountains Average Prices for Natural Gas
  
  Annual Data for Rocky Mountains:



Quarterly Data for Rocky Mountains:2007


2008


2009



Q1 2009


Q2 2009


Q3 2009


Q4 2009CIG ($/MMBtu)

$
3.97


$
6.24


$
3.07



$
3.27


$
2.36


$
2.67


$
3.96Pipeline throughput
    (MMBtu/d)(1)


788,210



945,925



975,785




1,005,998



980,694



952,126



965,033Producer services throughput (MMBtu/d)


224,525



220,792



165,579




181,385



166,022



157,362



157,896Segment gross margin (in
    thousands)(2)

$
1,145


$
5,877


$
3,254



$
799


$
711


$
634


$
1,110     (1)
    
    Includes 100% of Bighorn and Fort Union.(2)
    
    Excludes results and volumes associated with our equity
    interests in Bighorn and Fort Union.  Trends in Drilling and Production
    Activity.
   53




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Other Industry Trends.
  Credit and Capital Market Disruptions.
    Factors
    Affecting Operating Results and Financial
    Condition
     54




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##### Table of Contents



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.
   55




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##### Table of Contents



mark-to-market
      Operations and Maintenance Expenses.
  General and Administrative Expenses.
  EBITDA and Adjusted EBITDA.
 56




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##### Table of Contents




    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.    Total Distributable Cash Flow. mark-to-market
       57




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##### Table of Contents



Year Ended December 31,2009


2008


2007(In thousands)Reconciliation of total segment gross margin to operating income:Operating income

$
72,355


$
105,703


$
89,592Add:Operations and maintenance expenses


51,477



53,824



40,706Depreciation, amortization and impairment


56,975



52,916



39,875General and administrative expenses


39,511



45,571



34,638Taxes other than income


3,732



3,019



2,637Equity in earnings from unconsolidated affiliates


(4,600
)


(6,889
)


(2,850
)Total segment gross margin

$
219,450


$
254,144


$
204,598Reconciliation of EBITDA and adjusted EBITDA to net income:Net income

$
23,158


$
58,213


$
63,175Add:Depreciation, amortization and
    impairment(1)


57,539



53,154



39,967Interest and other financing costs


55,836



64,978



29,351Provision for income taxes


794



1,249



1,714EBITDA

$
137,327


$
177,594


$
134,207Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


19,203



19,116



4,589Copanos share of depreciation and amortization included in
    equity in earnings from unconsolidated affiliates


9,493



5,863



1,830Copanos share of interest and other financing costs
    incurred by our equity method investments


1,303



3,259



444Adjusted EBITDA

$
167,326


$
205,832


$
141,070Reconciliation of EBITDA and adjusted EBITDA to cash flows from
    operating activities:Cash flow provided by operating activities

$
141,318


$
89,924


$
128,218Add:Cash paid for interest and other financing costs


51,881



60,510



27,685Equity in earnings from unconsolidated affiliates


4,600



6,889



2,850Distributions from unconsolidated affiliates


(20,931
)


(22,460
)


(3,706
)Risk management activities


(30,155
)


27,037



5,201Changes in working capital and other


(9,386
)


15,694



(26,041
)EBITDA


137,327



177,594


$
134,207Add:Amortization of difference between the carried investment and
    the underlying equity in net assets of equity investments


19,203



19,116



4,589Copanos share of depreciation and amortization included in
    equity in earnings loss from unconsolidated affiliates


9,493



5,863



1,830Copanos share of interest and other financing costs
    incurred by our equity method investments


1,303



3,259



444Adjusted EBITDA

$
167,326


$
205,832


$
141,070Reconciliation of net income to total distributable cash flow:Net income

$
23,158


$
58,213


$
63,175Add: Depreciation, amortization and
    impairment(1)


57,539



53,154



39,967Amortization of commodity derivative options


36,950



32,842



21,045Amortization of debt issue costs


3,955



4,467



1,666Equity-based compensation


8,252



7,789



3,223G&A reimbursement from pre-IPO unitholders










12,414Distributions from unconsolidated affiliates


29,684



25,830



8,710Unrealized (gains) losses associated with line fill
    contributions and gas imbalances


(2,145
)


592



(12
)Unrealized (gains) losses on derivatives


(6,879
)


12,751



10,248Deferred taxes and other


271



1,927



1,096Less: Equity in earnings from unconsolidated affiliates


(4,600
)


(6,889
)


(2,850
)Maintenance capital
    expenditures


(9,728
)


(11,769
)


(9,062
)Total distributable cash
    flow(2)

$
136,457


$
178,907


$
149,620     (1)
    
    Includes activity related to the
    discontinued operations of the crude oil pipeline and related
    assets discussed in Note 15, Discontinued
    Operations, to our consolidated financial statements
    included in Item 8 of this report.(2)
    
    Prior to any retained cash reserves
    established by our Board of Directors. 58




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##### Table of Contents



How We
    Manage Our Operations
    Economic Models and Standardized Processing
    Margin.
  processing margin
  
    NGLs we extract in processing; and
    the thermal equivalent of natural gas attributable to those NGLs
    plus the natural gas consumed as fuel in extracting those NGLs.    Flow and Transaction Monitoring Systems.
  Producer Activity Evaluation and Reporting.
  Imbalance Monitoring and Control.
 59




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##### Table of Contents



month-to-month
  Our
    Contracts
  percentage-of-proceeds, percentage-of-index
    agreed-upon
  Fee-Based Arrangements.
  Percentage-of-Proceeds
    Arrangements. percentage-of-proceeds
  Percentage-of-Index
    Arrangements. percentage-of-index
  Keep-Whole with Fee Arrangements.
 60




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Our Contracts with Kinder Morgan. 30-inch-diameter Laredo-to-Katy
    Laredo-to-Katy Laredo-to-Katy
  Our
    Long-Term Growth Strategy
  per-unit
 61




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Forward-Looking
    Statements
    
    our ability to successfully integrate any acquired asset or
    operations;
    the volatility of prices and market demand for natural gas,
    crude oil and NGLs;
    our ability to continue to obtain new sources of natural gas
    supply;
    our ability to access NGL fractionation capacity;
    the ability of key producers to continue to drill and
    successfully complete and attach new natural gas supplies;
    our ability to retain 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.   62




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Our
    Results of Operation
  Year Ended December 31,2009


2008


2007($ In thousands)Total segment gross
    margin(1)(2)

$
219,450


$
254,144


$
204,598Operations and maintenance
    expenses(2)


51,477



53,824



40,706Depreciation, amortization and
    impairment(2)


56,975



52,916



39,875General and administrative expenses


39,511



45,571



34,638Taxes other than income


3,732



3,019



2,637Equity in earnings from unconsolidated affiliates


(4,600
)


(6,889
)


(2,850
)Operating income


72,355



105,703



89,592Gain on retirement of unsecured debt


3,939



15,272



Interest and other financing costs, net


(54,634
)


(63,804
)


(26,497
)Provision for income taxes


(794
)


(1,249
)


(1,714
)Discontinued operations, net of tax


2,292



2,291



1,794Net income

$
23,158


$
58,213


$
63,175Total segment gross margin:Oklahoma(2)

$
76,686


$
133,112


$
112,763Texas


103,620



142,723



121,935Rocky Mountains


3,254



5,877



1,145Segment gross
    margin(2)


183,560



281,712



235,843Corporate and
    other(3)


35,890



(27,568
)


(31,245
)Total segment gross
    margin(1)(2)

$
219,450


$
254,144


$
204,598Segment gross margin per unit:Oklahoma:Service throughput
    ($/MMBtu)(2)(4)

$
0.80


$
1.52


$
1.55Texas:Service throughput
    ($/MMBtu)(5)

$
0.46


$
0.57


$
0.52Rocky Mountains:Producer service throughput
    ($/MMBtu)(6)

$
0.04


$
0.06


$
0.06Volumes:Oklahoma:(4)(7)Service throughput (MMBtu/d)


262,259



238,836



199,906Plant inlet volumes (MMBtu/d)


163,474



156,057



144,050NGLs produced (Bbls/d)


15,977



15,126



13,771Texas:(5)(8)Service throughput (MMBtu/d)


619,615



686,791



642,528Pipeline throughput (MMBtu/d)


290,627



314,252



296,288Plant inlet volumes (MMBtu/d)


539,633



610,249



567,073NGLs produced (Bbls/d)


17,959



16,150



18,275Rocky Mountains:Producer service throughput
    (MMBtu/d)(6)


165,579



220,792



224,525Maintenance capital expenditures

$
9,728


$
11,769


$
9,062Expansion capital expenditures


61,424



169,056



884,290Total capital expenditures

$
71,152


$
180,825


$
893,352Operations and maintenance expenses:Oklahoma(2)

$
23,469


$
23,874


$
20,261Texas


27,960



29,950



20,437Rocky Mountains


48







8Total operations and maintenance
    expenses(2)

$
51,477


$
53,824


$
40,706     (1)
    
    Total segment gross margin is a non-GAAP financial measure. See
     How We Evaluate Our Operations for a
    reconciliation of total segment gross margin to its most
    directly comparable GAAP measure of operating income.(2)
    
    Excludes results attributable to our crude oil pipeline and
    related assets, which are classified as discontinued operations
    as discussed in Note 15, Discontinued
    Operations, in our consolidated financial statements
    included in Item 8 of this report. 63




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(3)
    
    Corporate and other includes results attributable to
    Copanos commodity risk management activities.(4)
    
    Excludes volumes associated with our interest in Southern Dome.
    For 2009, plant inlet volumes for Southern Dome averaged
    13,137 MMBtu/d and NGLs produced averaged 478 Bbls/d.
    For 2008, plant inlet volumes for Southern Dome averaged
    9,923 MMBtu/d and NGLs produced averaged 364 Bbls/d.
    For 2007, plant inlet volumes for Southern Dome averaged
    6,061 MMBtu/d and NGLs produced averaged 244 Bbls/d.(5)
    
    Excludes results and volumes associated with our interest in
    Webb Duval. Volumes transported by Webb Duval, net of
    intercompany volumes, were 78,160 MMBtu/d,
    91,342 MMBtu/d and 93,887 MMBtu/d for 2009, 2008 and
    2007, respectively.(6)
    
    Producer services throughput consists of volumes purchased for
    resale, volumes gathered under firm capacity gathering
    agreements with Fort Union and volumes transported using
    firm capacity agreements with WIC. Excludes results and volumes
    associated with our interests in Bighorn and Fort Union.
    Combined volumes gathered by Bighorn and Fort Union were
    975,785 MMBtu/d and 945,925 MMBtu/d for 2009 and 2008,
    respectively.(7)
    
    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 2009, plant inlet volumes averaged 126,776 MMBtu/d and
    NGLs produced averaged 13,044 Bbls/d for plants owned by
    the Oklahoma segment. For 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
    2007, plant inlet volumes averaged 93,173 MMBtu/d and NGLs
    produced averaged 9,349 Bbls/d for plants owned by the
    Oklahoma segment.(8)
    
    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 525,413 MMBtu/d
    and NGLs produced averaged 16,810 Bbls/d for 2009 for
    plants owned by the Texas segment. Plant inlet volumes averaged
    596,535 MMBtu/d and NGLs produced averaged
    14,715 Bbls/d for 2008 for plants owned by the Texas
    segment. Plant inlet volumes averaged 552,690 MMBtu/d and
    NGLs produced averaged 16,317 Bbls/d for 2007 for plants
    owned by the Texas segment.  Year
    Ended December 31, 2009 Compared with Year Ended
    December 31, 2008
    
    a decrease in total segment gross margin of $34.7 million,
    consisting of a $98.2 million decrease in operating segment
    gross margins primarily reflecting average NGL price declines of
    42% on the Conway index and 45% on the Mt. Belvieu index and
    lower overall service throughput volumes, offset by an increase
    of $63.5 million from commodity risk management activities;
    an increase in depreciation, amortization and impairment
    expenses of $4.1 million primarily related to expanded
    operations in north Texas;
    a decrease of $11.3 million attributable to lower gain on
    the retirement of debt in 2009;
    an increase in taxes other than income taxes of
    $0.7 million; and
    a decrease of $2.3 million in equity in earnings of
    unconsolidated affiliates primarily as a result of a noncash
    impairment charge associated with inactive pipelines owned by
    Bighorn, of which our portion totaled $1.8 million;    
    a decrease in general and administrative expenses of
    $6.1 million and operations and maintenance expenses of
    $2.4 million primarily related to reduced bad debt expense
    and successful cost reduction efforts, including reduced
    employee compensation expense and third-party service provider
    fees;
    a decrease of $9.2 million in interest expense primarily
    related to (i) a noncash
    mark-to-market
    gain on interest rate swaps for 2009 of $2.8 million
    compared to a $10.0 million loss in 2008, a change of 64




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$12.8 million, and (ii) reduced amortization expense
    related to debt issuance costs of $0.6 million, offset by
    an increase in interest paid of $4.2 million as a result of
    increased average outstanding borrowings offset by lower average
    interest rates between the periods; and  
    a decrease in income taxes of $0.4 million.  Oklahoma Segment Gross Margin.
  Texas Segment Gross Margin.
  Rocky Mountains Segment Gross Margin.
  Corporate and Other. mark-to-market mark-to-market
  Operations and Maintenance
    Expenses.
  Depreciation, Amortization and
    Impairment.
 65




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General and Administrative Expenses.
  Interest and Other Financing Costs. mark-to-market mark-to-market
  Gain on Unsecured Debt Retirement.
  Year
    Ended December 31, 2008 Compared with Year Ended
    December 31, 2007
    
    an increase in total segment gross margin of $49.5 million,
    primarily as a result of a $45.8 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 $32.9 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
    (i) $10.0 million of
    mark-to-market
    losses on Copanos undesignated interest rate swaps,
    (ii) $3.5 million of goodwill impairment related to
    the Rocky Mountains acquisition and additional amortization of
    the basis differential on our investment in Bighorn,
    (iii) a 66




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##### Table of Contents



$1.3 million write-off of certain accounts receivable
    balances and (iv) 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);
    a decrease in interest income of $1.7 million; and
    an increase in the results of discontinued operations of
    $0.5 million as a result of the sale of the crude line
    operations.  Oklahoma Segment Gross Margin.
  Texas Segment Gross Margin.
  Rocky Mountains Segment Gross Margin.
  Corporate and Other. mark-to-market mark-to-market
  Operations and Maintenance
    Expenses.
  Depreciation, Amortization and
    Impairment.
  General and Administrative Expenses.
 67




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Interest and Other Financing Costs. mark-to-market
  Gain on Unsecured Debt Retirement.
  Cash
    Flows
    Year Ended December 31,2009


2008


2007(In thousands)Net cash provided by operating activities

$
141,318


$
89,924


$
128,218Net cash used in investing activities


(70,967
)


(198,855
)


(727,052
)Net cash (used in) provided by financing activities


(89,343
)


99,950



632,015     Operating Cash Flows.
  
    risk management activities provided an additional
    $57.2 million of cash flow for 2009 as compared to 2008,
    primarily because we purchased commodity derivative instruments
    totaling $6.9 million during 2009, whereas in 2008, we
    purchased $60.2 million of commodity derivative instruments;    
    cash distributions received from our unconsolidated affiliates
    (Bighorn, Fort Union, Webb Duval and Southern Dome) were
    $1.5 million lower in 2009 compared to 2008; and 68




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
    interest payments for 2009 were $4.3 million higher
    compared to the same period in 2008 as a result of issuing
    $300 million of senior unsecured notes in May 2008
    partially offset by interest savings as a result of retiring
    $67.8 million of senior unsecured notes from November 2008
    through March 2009.    
    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;    
    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.  Investing Cash Flows.
      Financing Cash Flows.
     69




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Liquidity
    and Capital Resources
  Sources of Liquidity.
  Effects of Recent Economic Changes;
    Outlook.
        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 70




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
    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.      Cash Distributions.
  One Quarter


Four QuartersCommon
    units(1)


31,911



127,645     (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 1, 2010, we had 105,501
    outstanding restricted units and 697,636 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

$
852,190


$



$
270,000


$



$
582,190Interest(1)


343,082



51,358



101,703



92,608



97,413Gathering and transportation firm commitments


119,251



14,458



32,756



29,817



42,220Operating leases


7,044



3,360



2,304



953



427Total contractual cash
    obligations(2)

$
1,321,567


$
69,176


$
406,763


$
123,378


$
722,250     (1)
    
    These amounts exclude estimates of
    the effect of our interest rate swap contracts on our future
    interest obligations. As of December 31, 2009, the fair
    value of our interest rate swap contracts, which expire between
    July 2010 and October 2012, totaled $8.1 million.(2)
    
    These amounts exclude capital
    expenditures we have committed to approved capital projects.   71




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Our
    Indebtedness
    Credit Ratings.
  Revolving Credit Facility.
         72




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##### Table of Contents




    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
    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.
     73




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##### Table of Contents




    sell assets;
    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
  GAAP Codification
  Accounting
    Standards Codification (ASC) and the Hierarchy of
    Generally Accepted Accounting Principles
    (GAAP),
 74




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Subsequent
    Events
  Subsequent Events
  Fair
    Value Measurements
  No. 2010-06, Fair Value Measurements and Disclosures: Improving
    Disclosures about Fair Value Measurements 2010-06), 820-10 2010-06 2010-06
  28-1, Interim Disclosures about Fair Value of Financial
    Instruments 107-1)
  No. SFAS 157-2), Effective Date of FASB Statement No. 157,
  820-10 FAS 157-4) Determining Fair Value When the Volume and Level of
    Activity for the Asset or Liability Have Significantly Decreased
    and Identifying Transactions That Are Not Orderly 820-10-65-4
  Business
    Combinations
  Business Combinations
  Disclosures
    about Derivative Instruments and Hedging Activities 
    an amendment of FASB Statement No. 133
  815-10, Disclosures about Derivative Instruments and Hedging
    Activities  an amendment of FASB Statement
    No. 133 815-10
 75




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##### Table of Contents



Accounting for Derivative
    Instruments and Hedging Activities, 815-10
  Useful
    Life of Intangible Assets
  350-30, Determination of the Useful Life of Intangible
    Assets No. 142-3), Goodwill and Other Intangible Assets, 350-30
  Critical
    Accounting Policies and Estimates
    Investments
    in Unconsolidated Affiliates
    Investments 
    Equity Method and Joint Ventures
 76




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##### Table of Contents



Impairment
    of Long-Lived Assets
  Accounting for the
    Impairment or Disposal of Long-Lived Assets,
    
    changes in general economic conditions in which our assets are
    located;
    the availability and prices of natural gas supply;
    improvements in exploration and production technology;
    the finding and development cost for producers to exploit
    reserves in a particular area;
    our ability to negotiate favorable agreements with producers and
    customers;
    our dependence on certain significant customers, producers,
    gatherers and transporters of natural gas; and
    competition from other midstream service providers, including
    major energy companies.    Revenue
    Recognition
  customer-by-customer
   77




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##### Table of Contents



agreed-upon  Our Contracts
  Risk
    Management Activities
     78




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Item 7A.
    Quantitative
    and Qualitative Disclosures about Market Risk      Commodity
    Price Risk
    Oklahoma. percentage-of-proceeds agreed-upon percentage-of-index
  Texas. fee-for-service percentage-of-index
    Rocky Mountains.
  Other Commodity Price Risks.
 79




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Sensitivity.
  Risk
    Management Oversight
         80




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##### Table of Contents



Commodity
    Price Hedging Activities
  Permitted Derivative Instruments.
  
    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 NGLs 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),
    fixed-for-floating
    swaps or
    floating-for-floating
    swaps (basis swaps) on natural gas at Henry Hub, Houston Ship
    Channel 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.  Limitations.
  
    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;
    Except as provided below under Exception to Volume
    Limitations, we may not (i) purchase crude oil or
    NGLs 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 NGLs 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
    exceed 80% of the projected requirements or output, as
    applicable, for the hedged period. We are required to divest
    outstanding hedge positions only 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;
    The aggregate volumetric exposure associated with swaps (other
    than basis 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; and
    We may not enter into a basis swap if, as a result of the
    proposed transaction, net notional hedged volumes with respect
    to the underlying hedged basis would exceed 80% of the projected
    requirements or output, as applicable, for the hedged period. We
    are required to divest outstanding basis swaps only to the
    extent net notional hedged volumes with respect to an underlying
    hedged basis exceed 100% of the projected requirements or
    output, as applicable, for the hedged period.    Exception to Volume Limitations. out-of-the-money out-of-the-money. in-the-money,
 81




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##### Table of Contents



Approved Markets. over-the-counter
    Oklahoma Segment.
  Texas Segment.
  Rocky Mountains Segment.
  Our
    Commodity Hedge Portfolio
     82




---



##### Table of Contents



Interest Rates.
      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, 2009
  Rules 13a-15(f) 15d-15(f) Rules 13a-15(f))
      Form 10-K,
  Rules 13a-15(f) 15d-15(f)
  /s/  R.
    Bruce NorthcuttR.
    Bruce Northcutt
    President and Chief Executive Officer

/s/  Carl
    A. LunaCarl
    A. Luna
    Senior Vice President and Chief Financial Officer  85




---



##### Table of Contents



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




---



##### 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). 88




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##### Table of Contents



Number

Description4
.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

Amended and Restated Copano Energy, L.L.C. Long-Term Incentive
    Plan (incorporated by reference to Exhibit 99.1 to Current
    Report on
    Form 8-K
    filed February 24, 2009).10
.2

Amendment to Amended and Restated Copano Energy, L.L.C.
    Long-Term Incentive Plan (incorporated by reference to
    Exhibit 99.2 to Current Report on
    Form 8-K
    filed May 18, 2009).10
.3*

Administrative and Operating Services Agreement effective
    January 1, 2010, among Copano/Operations, Inc. and CPNO
    Services, L.P.10
.4

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
.5

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
.6

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
.7

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
.8

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
.9

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
.10

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
.11

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
.12

First Amendment to Employment Agreement between ScissorTail
    Energy, L.L.C. and Sharon Robinson dated as of December 31,
    2008.10
.13

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
.14

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
.15

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
.16

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
.17

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
.18

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). 89




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##### Table of Contents



Number

Description10
.19

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
.20

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
.21

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
.22

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
.23

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
.24

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
.25

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
.26

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
.27

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
.28

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
.29

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
.30

Form of Unit Appreciation Right Award Agreement (incorporated by
    reference to Exhibit 99.1 to Current Report on
    Form 8-K
    filed May 18, 2009).10
.31

Form of Unit Appreciation Right Award Agreement (incorporated by
    reference to Exhibit 99.1 to Current Report on
    Form 8-K
    filed August 18, 2009).10
.32

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
.33

2009 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 24, 2009).10
.34

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
.35

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
.36

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
.37

Form of Indemnification Agreement (incorporated by reference to
    Exhibit 10.1 to Current Report on
    Form 8-K
    filed November 2, 2005).10
.38

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
.39

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
.40

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
.41

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). 90




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##### Table of Contents



Number

Description10
.42

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
.43

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
.44

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
.45

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 Principal
    Executive Officer.31
.2*

Sarbanes-Oxley Section 302 certification of Principal
    Financial Officer.32
.1*

Sarbanes-Oxley Section 906 certification of Principal
    Executive Officer.32
.2*

Sarbanes-Oxley Section 906 certification of Principal
    Financial Officer.     *
    
    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/  R.
    Bruce Northcutt     By:
    /s/  Carl
    A. Luna       Signature

Title

Date/s/  R.
    Bruce NorthcuttR.
    Bruce Northcutt

President and Chief Executive Officer and Director (Principal
    Executive Officer)

March 1, 2010/s/  Carl
    A. LunaCarl
    A. Luna

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

March 1, 2010/s/  Lari
    ParadeeLari
    Paradee

Senior Vice President, Controller and Principal Accounting
    Officer (Principal Accounting Officer)

March 1, 2010/s/  William
    L. ThackerWilliam
    L. Thacker

Chairman of the Board of Directors

March 1, 2010/s/  James
    G. CrumpJames
    G. Crump

Director

March 1, 2010/s/  Ernie
    L. DannerErnie
    L. Danner

Director

March 1, 2010/s/  Scott
    A. GriffithsScott
    A. Griffiths

Director

March 1, 2010/s/  Michael
    L. JohnsonMichael
    L. Johnson

Director

March 1, 2010/s/  T.
    William PorterT.
    William Porter

Director

March 1, 2010  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, 2009 and 2008


F-3Consolidated Statements of Operations for the
    years ended December 31, 2009, 2008 and 2007


F-4Consolidated Statements of Cash Flows for the
    years ended December 31, 2009, 2008 and 2007


F-5Consolidated Statements of Members Capital
    and Comprehensive (Loss) Income for the years ended
    December 31, 2009, 2008 and 2007


F-6Notes to Consolidated Financial Statements


F-7   F-1




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##### Table of Contents



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




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
 CONSOLIDATED
    BALANCE SHEETS  December 31,2009


2008(In thousands,except unit information)ASSETSCurrent assets:Cash and cash equivalents

$
44,692


$
63,684Accounts receivable, net


91,156



96,028Risk management assets


36,615



76,440Prepayments and other current assets


4,937



4,891Discontinued operations (Note 15)






5,564Total current assets


177,400



246,607Property, plant and equipment, net


841,323



819,099Intangible assets, net


190,376



198,341Investment in unconsolidated affiliates


618,503



640,598Escrow cash


1,858



1,858Risk management assets


15,381



82,892Other assets, net


22,571



24,270Total assets

$
1,867,412


$
2,013,665LIABILITIES AND MEMBERS CAPITALCurrent liabilities:Accounts payable

$
111,021


$
103,849Accrued interest


11,921



11,904Accrued tax liability


672



784Risk management liabilities


9,671



6,272Other current liabilities


9,358



16,787Total current liabilities


142,643



139,596Long-term debt (includes $628 and $704 bond premium as of
    December 31, 2009 and 2008, respectively)


852,818



821,119Deferred tax provision


1,862



1,718Risk management and other noncurrent liabilities


10,063



13,274Commitments and contingencies (Note 13)Members capital:Common units, no par value, 54,670,029 units and
    53,965,288 units issued and outstanding as of
    December 31, 2009 and 2008, respectively


879,504



865,343Class C units, no par value, 0 units and
    394,853 units issued and outstanding as of
    December 31, 2009 and 2008, respectively






13,497Class D units, no par value, 3,245,817 units issued
    and outstanding as of December 31, 2009 and 2008


112,454



112,454Paid-in capital


42,518



33,734Accumulated deficit


(158,267
)


(54,696
)Accumulated other comprehensive (loss) income


(16,183
)


67,626860,026



1,037,958Total liabilities and members capital

$
1,867,412


$
2,013,665    F-3




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
 CONSOLIDATED
    STATEMENTS OF OPERATIONS  Year Ended December 31,2009


2008


2007(In thousands, except per unit information)Revenue:Natural gas sales

$
316,686


$
747,258


$
518,431Natural gas liquids sales


406,662



597,986



491,432Transportation, compression and processing fees


55,983



59,006



22,306Condensate and other


40,715



50,169



32,346Total revenue


820,046



1,454,419



1,064,515Costs and expenses:Cost of natural gas and natural gas
    liquids(1)


576,448



1,178,304



853,969Transportation(1)


24,148



21,971



5,948Operations and maintenance


51,477



53,824



40,706Depreciation, amortization and impairment


56,975



52,916



39,875General and administrative


39,511



45,571



34,638Taxes other than income


3,732



3,019



2,637Equity in earnings from unconsolidated affiliates


(4,600
)


(6,889
)


(2,850
)Total costs and expenses


747,691



1,348,716



974,923Operating income


72,355



105,703



89,592Interest and other income


1,202



1,174



2,854Gain on retirement of unsecured debt


3,939



15,272



Interest and other financing costs


(55,836
)


(64,978
)


(29,351
)Income before income taxes


21,660



57,171



63,095Provision for income taxes


(794
)


(1,249
)


(1,714
)Income from continuing operations


20,866



55,922



61,381Discontinued operations, net of tax (Note 15)


2,292



2,291



1,794Net income

$
23,158


$
58,213


$
63,175Basic net income per common unit:Net income per common unit from continuing operations

$
0.39


$
1.15


$
1.44Net income per common unit from discontinued operations


0.04



0.05



0.04Net income per common unit

$
0.43


$
1.20


$
1.48Weighted average number of common units


54,395



48,513



42,456Diluted net income per common unit:Net income per common unit from continuing operations

$
0.36


$
0.97


$
1.32Net income per common unit from discontinued operations


0.04



0.04



0.04Net income per common unit

$
0.40


$
1.01


$
1.36Weighted average number of common units


58,038



57,856



46,516Basic net income per subordinated unit:Net income per subordinated unit

$



$



$
0.21Net income per subordinated unit from discontinued operations










Net income per subordinated unit

$



$



$
0.21Weighted average number of subordinated units










848Diluted net income per subordinated unit:Net income per subordinated unit

$



$



$
0.21Net income per subordinated unit from discontinued operations










Net income per subordinated unit

$



$



$
0.21Weighted average number of subordinated units










848     (1)
    
    Exclusive of operations and maintenance and depreciation,
    amortization and impairment shown separately below.   F-4




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##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  CONSOLIDATED STATEMENTS OF CASH FLOWS
  Year Ended December 31,2009


2008


2007(In thousands)Cash Flows From Operating Activities:Net income

$
23,158


$
58,213


$
63,175Adjustments to reconcile net income to net cash provided by
    operating activities:Depreciation and amortization


57,539



50,314



39,967Impairment of goodwill






2,840



Amortization of debt issue costs


3,955



4,467



1,666Equity in earnings from unconsolidated affiliates


(4,600
)


(6,889
)


(2,850
)Distributions from unconsolidated affiliates


20,931



22,460



3,706Gain on retirement of Senior Notes (Note 7)


(3,939
)


(15,272
)


Noncash (gain) loss on risk management activities, net


(6,879
)


12,751



10,248Equity-based compensation


8,455



5,858



3,223Deferred tax provision


144



486



1,231Other noncash items


(816
)


98



(136
)Changes in assets and liabilities, net of acquisitions:Accounts receivable


5,545



32,090



(34,890
)Prepayments and other current assets


67



(1,123
)


(204
)Risk management activities


30,155



(27,037
)


(5,201
)Accounts payable


8,764



(44,766
)


38,232Other current liabilities


(1,161
)


(4,566
)


10,051Net cash provided by operating activities


141,318



89,924



128,218Cash Flows From Investing Activities:Additions to property, plant and equipment


(73,232
)


(152,533
)


(80,898
)Additions to intangible assets


(3,060
)


(9,189
)


(3,406
)Acquisitions, net of cash acquired


(2,840
)


(12,655
)


(641,097
)Investment in unconsolidated affiliates


(4,228
)


(26,832
)


(1,727
)Distributions from unconsolidated affiliates


8,753



3,370



676Escrow cash






(1,858
)


Proceeds from sale of assets


6,061



28



241Other


(2,421
)


814



(841
)Net cash used in investing activities


(70,967
)


(198,855
)


(727,052
)Cash Flows From Financing Activities:Proceeds from long-term debt


70,000



579,000



663,781Repayments of long-term debt


(20,000
)


(339,000
)


(288,000
)Retirement of Senior Notes (Note 7)


(14,286
)


(34,313
)


Repayment of short-term notes payable










(1,495
)Deferred financing costs






(6,688
)


(10,677
)Distributions to unitholders


(125,721
)


(104,234
)


(73,629
)Proceeds from private placement of common units










157,125Proceeds from private placement of Class E units










177,875Capital contributions from Pre-IPO Investors (Note 8)






4,103



9,965Equity offering costs






(47
)


(4,741
)Proceeds from option exercises


664



1,129



1,811Net cash (used in) provided by financing activities


(89,343
)


99,950



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


(18,992
)


(8,981
)


33,181Cash and cash equivalents, beginning of year


63,684



72,665



39,484Cash and cash equivalents, end of year

$
44,692


$
63,684


$
72,665    F-5




---



##### Table of Contents



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


Comprehensive





Comprehensiveof Units


Units


of Units


Units


of Units


Units


of Units


Units


of Units


Units


Capital


(Deficit)


(Loss) Income


Total


(Loss) IncomeBalance, 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



1,037,958Conversion of Class C units into common units


395



13,497



(395
)


(13,497
)









































$
Distributions to unitholders














































(126,729
)






(126,729
)


Option exercises


62



664















































664



Equity-based compensation










































7,332











7,332



Vested restricted units


77























































Units issued for vested phantom units


29























































Vested unit awards


142







































1,452











1,452



Net income














































23,158







23,158



23,158Derivative settlements reclassified to income


















































(42,200
)


(42,200
)


(42,200
)Unrealized gain-change in fair value of derivatives


















































(41,609
)


(41,609
)


(41,609
)Comprehensive loss

























































$
(60,651
)Balance, December 31, 2009


54,670


$
879,504






$




3,246


$
112,454






$







$



$
42,518


$
(158,267
)

$
(16,183
)

$
860,026    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., its subsidiaries and entities it
    manages or operates
    Note 2 
    Summary
    of Significant Accounting Policies  Basis
    of Presentation and Principles of Consolidation
      two-for-one two-for-one
   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)  Investments
    in Unconsolidated Affiliates
    Investments 
    Equity Method and Joint Ventures
  Use of
    Estimates
    Cash
    and Cash Equivalents
    Concentration
    and Credit Risk
       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)    Allowance
    for Doubtful Accounts
    Balance at





Write-Offs,


Balance atBeginning


Charged to


Net of


End ofof Period


Expense


Recoveries


PeriodYear ended December 31, 2009

$
88


$
389


$
(266
)

$
211Year ended December 31, 2008


166



1,269



(1,347
)


88Year ended December 31, 2007


64



69



33



166   Property,
    Plant and Equipment
    Useful LivesPipelines and equipment


3-30 yearsGas processing plants and equipment


20-30 yearsOther property and equipment


3-10 years     Intangible
    Assets
  rights-of-way, 350-30 No. 142-3), rights-of-way rights-of-way 2010
     2011 
 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)  2012  2013  2014 
  December 31,2009


2008Rights-of-way
    and easements, at cost

$
116,122


$
113,061Less accumulated amortization for
    rights-of-way
    and easements


(18,204
)


(11,910
)Contracts


107,916



107,916Less accumulated amortization for contracts


(19,330
)


(14,901
)Customer relationships


4,864



4,864Less accumulated amortization for customer relationships


(992
)


(689
)Intangible assets, net

$
190,376


$
198,341   rights-of-way rights-of-way
  Impairment
    of Long-Lived Assets
  Accounting for the
    Impairment or Disposal of Long-Lived Assets,
    
    changes in general economic conditions in which our assets are
    located;
    the availability and prices of natural gas supply;
    improvements in exploration and production technology;
    the finding and development cost for producers to exploit
    reserves in a particular area;
    our ability to negotiate favorable agreements with producers and
    customers; 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)   
    our dependence on certain significant customers, producers,
    gatherers and transporters of natural gas; and
    competition from other midstream service providers, including
    major energy companies.    Risk
    Management Activities
    Goodwill
  Intangibles  Goodwill and Other
  Other
    Assets
    Transportation
    and Exchange Imbalances
    Asset
    Retirement Obligations
   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)    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-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)  producer or third-party transporter. Because the extraction of
    NGLs from the natural gas during processing or conditioning
    reduces the Btu content of the natural gas, we 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.  Derivatives
  Accounting for
    Derivative Instruments and Hedging Activities,
        Interest
    and Other Financing Costs
  mark-to-market
 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)  Income
    Taxes
    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-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)    Year Ended December 31,2009


2008


2007(In thousands, except per unit information)Net income available  basic and diluted

$
23,158


$
58,213


$
63,175Less net income attributable to subordinated units










(175
)Net income available  basic common units


23,158



58,213



63,000Net income reallocated from subordinated units










175Net income available  diluted common
    units(1)(2)

$
23,158


$
58,213


$
63,175Basic weighted average common units


54,395



48,513



42,456Dilutive weighted average common
    units(1)(2)


58,038



57,856



46,516Basic net income per unit:Income per common unit from continuing operations

$
0.39


$
1.15


$
1.44Income per common unit from discontinued operations


0.04



0.05



0.04Net income per common unit

$
0.43


$
1.20


$
1.48Diluted net income per unit:Income per common unit from continuing
    operations(1)(2)

$
0.36


$
0.97


$
1.32Income per common unit from discontinued
    operations(1)(2)


0.04



0.04



0.04Net income per common unit

$
0.40


$
1.01


$
1.36     (1)
    
    Our potentially dilutive common equity includes the following:  Year Ended December 31,2009

2008

2007(In thousands)Employee options


93



326



537Unit appreciation rights


7







Restricted units


4



47



138Phantom units


84



19



Contingent incentive plan unit awards


78



198



Class C units


131



812



743Class D units


3,246



3,246



658Class 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:  F-15




---



##### 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 31,2009

2008

2007(In thousands)Employee options


1,210



1,085



906Unit appreciation rights


296







Restricted units


101



123



103Phantom Units


614



570



101   Equity-Based
    Compensation
    Note 3 
    New
    Accounting Pronouncements  GAAP Codification
  Accounting
    Standards Codification (ASC) and the Hierarchy of
    Generally Accepted Accounting Principles
    (GAAP),
  Subsequent
    Events
  Subsequent Events
  Fair
    Value Measurements
  No. 2010-06, Fair Value Measurements and Disclosures: Improving
    Disclosures about Fair Value Measurements 820-10 2010-06
 F-16




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 3 
    New
    Accounting Pronouncements (Continued)  2010-06
  28-1, Interim Disclosures about Fair Value of Financial
    Instruments (FSP 107-1)
  No. SFAS 157-2), Effective Date of FASB Statement No. 157,
  820-10 FAS 157-4) Determining Fair Value When the Volume and Level of
    Activity for the Asset or Liability Have Significantly Decreased
    and Identifying Transactions That Are Not Orderly  820-10
  Business
    Combinations
  Business Combinations
  Disclosures
    about Derivative Instruments and Hedging Activities 
    an amendment of FASB Statement No. 133
  815-10, Disclosures about Derivative Instruments and Hedging
    Activities  an amendment of FASB Statement
    No. 133 815-10 815-10 815-10.
 F-17




---



##### 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
  350-30, Determination of the Useful Life of Intangible
    Assets No. 142-3), Goodwill and Other Intangible Assets, 350-30
  Note 4 
    Acquisitions  2007
    Acquisitions
  Acquisition of Cantera Natural Gas LLC.
    Acquisition of Cimmarron Gathering, LP.
 F-18




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)    Year EndedDecember 31, 2007(In thousands, except per unitinformation)Pro Forma Earnings Data:Revenue

$
1,193,198Costs and expenses

$
1,092,525Equity in earnings from unconsolidated affiliates

$
3,134Operating income

$
100,673Income before extraordinary items

$
51,736Net income

$
51,736Basic net income per unit:As reported units outstanding


42,456Pro forma units outstanding


46,301As reported net income per unit

$
1.48Pro forma net income per unit

$
1.11Diluted net income per unit:As reported units outstanding


46,516Pro forma units outstanding


57,659As reported net income per unit

$
1.36Pro forma net income per unit

$
0.90Basic net income per subordinated unit:As reported units outstanding


848Pro forma units outstanding


848As reported net income per unit

$
0.21Pro forma net income per unit

$
0.21Diluted net income per subordinated unit:As reported units outstanding


848Pro forma units outstanding


848As reported net income per unit

$
0.21Pro forma net income per unit

$
0.21   2008
    Acquisitions
   F-19




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 4 
    Acquisitions
    (Continued)    Note 5 
    Property,
    Plant and Equipment and Asset Retirement Obligations    December 31,2009


2008Property, plant and equipment, at costPipelines and equipment

$
757,061


$
717,010Gas processing plant and equipment


221,126



148,482Construction in progress


29,457



80,901Office furniture and equipment


11,845



7,4381,019,489



953,831Less accumulated depreciation and amortization


(178,166
)


(134,732
)Property, plant and equipment, net

$
841,323


$
819,099   Asset retirement obligations. (i) rights-of-way
    ARO liability balance, December 31, 2007

$
555AROs incurred in 2008


78Accretion for conditional obligations


40ARO liability balance, December 31, 2008


673ARO incurred in 2009


19Accretion for conditional obligations


47ARO liability balance, December 31, 2009

$
739       Note 6 
    Investment
    in Unconsolidated Affiliates   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)      Webb
    Duval
      Year Ended December 31,2009


2008


2007Operating revenue

$
2,109


$
4,064


$
3,802Operating expenses


(1,880
)


(2,225
)


(826
)Depreciation


(786
)


(779
)


(768
)Net (loss) income


(557
)


1,060



2,208Ownership %


62.5
%


62.5
%


62.5
%(348
)


663



1,380Copanos share of management fee charged


138



135



132Amortization of difference between the carried investment and
    the underlying equity in net assets


21



21



21Equity in (loss) earnings from unconsolidated affiliate

$
(189
)

$
819


$
1,533Distributions from unconsolidated affiliate

$
766


$
1,359


$
2,401Current assets

$
318


$
1,708


$
1,920Noncurrent assets


6,187



6,909



7,426Current liabilities


(827
)


(1,161
)


(779
)Noncurrent liabilities


(59
)


(55
)


(51
)Net assets

$
5,619


$
7,401


$
8,516  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)  Southern
    Dome
      Year Ended December 31,2009


2008


2007Operating revenue

$
18,996


$
29,715


$
16,198Operating expenses


(15,860
)


(24,483
)


(13,683
)Depreciation


(829
)


(744
)


(736
)Net income


2,307



4,488



1,779Ownership %(1)


69.5
%


69.5
%


69.5
%1,603



3,119



1,236Copanos share of management fee charged


174



174



173Amortization of difference between the carried investment and
    the underlying equity in net assets


(9
)


(10
)


(9
)Equity in earnings from unconsolidated affiliate

$
1,768


$
3,283


$
1,400Distributions from unconsolidated affiliate

$
2,850


$
3,579


$
1,981Current assets

$
3,617


$
2,371


$
4,434Noncurrent assets


15,567



16,367



16,802Current liabilities


(4,902
)


(2,637
)


(4,473
)Net assets

$
14,282


$
16,101


$
16,763     (1)
    
    Represents Copanos right to distributions from Southern
    Dome.  Bighorn
    and Fort Union
     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)      Year Ended December 31,2009Bighorn


Fort UnionOperating revenue

$
35,980


$
63,013Operating expenses


(15,879
)


(6,857
)Depreciation and impairment


(10,579
)


(8,180
)Interest expense and other, net


9



(3,509
)Net income


9,531



44,467Ownership %


51
%


37.04
%4,861



16,471Priority allocation of earnings and other


702



(287
)Copanos share of management fee charged


276



84Amortization of difference between the carried investment and
    the underlying equity in net assets


(12,791
)


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

$
(6,952
)

$
9,845Distributions from unconsolidated affiliates

$
12,244


$
13,723Current assets

$
7,115


$
12,339Noncurrent assets


92,617



212,416Current liabilities


(1,598
)


(21,146
)Noncurrent liabilities


(238
)


(87,677
)Net assets

$
97,896


$
115,932   F-23




---



##### 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, net


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   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   F-24




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
  Note 7 
    Long-Term
    Debt    December 31,2009


2008Long-term debt:Credit Facility

$
270,000


$
220,000Senior Notes:8.125% senior unsecured notes due 2016


332,665



332,665Unamortized bond premium -senior notes due 2016


628



7047.75% senior unsecured notes due 2018


249,525



267,750Total Senior Notes


582,818



601,119Total

$
852,818


$
821,119   Senior
    Secured Revolving Credit Facility
         F-25




---



##### 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).        
    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.
 F-26




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
      7.75% Senior Notes Due 2018.
    General.
        
    sell assets;
    pay distributions on, redeem or repurchase our units, or redeem
    or repurchase our subordinated debt; F-27




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 7 
    Long-Term Debt (Continued)
   
    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-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 BALANCE SHEETS
  December 31, 2009


December 31, 2008Investment 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

$
3,861


$



$
40,831


$



$



$
44,692


$
20,417


$



$
43,267


$



$



$
63,684Accounts receivable, net


29







91,127











91,156



1







96,027











96,028Intercompany receivable


21,034







(21,034
)














110,551







(110,551
)










Risk management assets










36,615











36,615











76,440











76,440Prepayments and other current assets


3,610







1,327











4,937



911







3,980











4,891Discontinued operations


































5,564











5,564Total current assets


28,534







148,866











177,400



131,880







114,727











246,607Property, plant and equipment, net


96







841,227











841,323



136







818,963











819,099Intangible assets, net










190,376











190,376











198,341











198,341Investment in unconsolidated affiliates










618,503



618,503



(618,503
)


618,503











640,598



640,598



(640,598
)


640,598Investment in consolidated subsidiaries


1,684,994















(1,684,994
)






1,723,814















(1,723,814
)


Escrow cash










1,858











1,858











1,858











1,858Risk management assets










15,381











15,381











82,892











82,892Other assets, net


15,854







6,717











22,571



19,809







4,461











24,270Total assets

$
1,729,478


$



$
1,822,928


$
618,503


$
(2,303,497
)

$
1,867,412


$
1,875,639


$



$
1,861,840


$
640,598


$
(2,364,412
)

$
2,013,665LIABILITIES AND MEMBERS/PARTNERS CAPITALCurrent liabilities:Accounts payable

$



$



$
111,021


$



$



$
111,021


$
2


$



$
103,847


$



$



$
103,849Accrued interest


11,146







775











11,921



11,878







26











11,904Accrued tax liability


672



















672



784



















784Risk management liabilities










9,671











9,671











6,272











6,272Other current liabilities


2,637







6,721











9,358



1,731







15,056











16,787Total current liabilities


14,455







128,188











142,643



14,395







125,201











139,596Long-term debt


852,818



















852,818



821,119



















821,119Deferred tax provision


1,862



















1,862



1,718



















1,718Risk management and other noncurrent liabilities


317







9,746











10,063



449







12,825











13,274Members/Partners capital:Common units


879,504



















879,504



865,343



















865,343Class C units


























13,497



















13,497Class D units


112,454



















112,454



112,454



















112,454Class E units














































Paid-in capital


42,518



1



1,191,268



595,775



(1,787,044
)


42,518



33,734



1



1,544,237



629,359



(2,173,597
)


33,734Accumulated (deficit) earnings


(158,267
)


(1
)


509,909



22,728



(532,636
)


(158,267
)


(54,696
)


(1
)


111,951



11,239



(123,189
)


(54,696
)Other comprehensive (loss) income


(16,183
)






(16,183
)






16,183



(16,183
)


67,626







67,626







(67,626
)


67,626860,026







1,684,994



618,503



(2,303,497
)


860,026



1,037,958







1,723,814



640,598



(2,364,412
)


1,037,958Total liabilities and members/partners capital

$
1,729,478


$



$
1,822,928


$
618,503


$
(2,303,497
)

$
1,867,412


$
1,875,639


$



$
1,861,840


$
640,598


$
(2,364,412
)

$
2,013,665  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 OPERATIONS
  Year Ended December 31, 2009


Year Ended December 31, 2008Investment 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

$



$



$
316,686


$



$



$
316,686


$



$



$
747,258


$



$



$
747,258Natural gas liquids sales










406,662











406,662











597,986











597,986Transportation, compression and processing fees










55,983











55,983











59,006











59,006Condensate and other










40,715











40,715











50,169











50,169Total revenue










820,046











820,046











1,454,419











1,454,419Costs and expenses:Cost of natural gas and natural gas liquids










576,448











576,448











1,178,304











1,178,304Transportation










24,148











24,148











21,971











21,971Operations and maintenance










51,477











51,477



948







52,876











53,824Depreciation, amortization and impairment


40







56,935











56,975



44







52,872











52,916General and administrative


19,329







20,182











39,511



25,610







19,961











45,571Taxes other than income










3,732











3,732











3,019











3,019Equity in earnings from unconsolidated affiliates










(4,600
)


(4,600
)


4,600



(4,600
)










(6,889
)


(6,889
)


6,889



(6,889
)Total costs and expenses


19,369







728,322



(4,600
)


4,600



747,691



26,602







1,322,114



(6,889
)


6,889



1,348,716Operating (loss) income


(19,369
)






91,724



4,600



(4,600
)


72,355



(26,602
)






132,305



6,889



(6,889
)


105,703Other income (expense):Interest and other income










1,202











1,202



47







1,127











1,174Gain on retirement of unsecured debt


3,939



















3,939



15,272



















15,272Interest and other financing costs


(53,180
)






(2,656
)










(55,836
)


(53,172
)






(11,806
)










(64,978
)(Loss) income before income taxes, discontinued operations and
    equity in earnings from consolidated subsidiaries


(68,610
)






90,270



4,600



(4,600
)


21,660



(64,455
)






121,626



6,889



(6,889
)


57,171Provision for income taxes


(794
)


















(794
)


(1,249
)


















(1,249
)(Loss) income before discontinued operations and equity in
    earnings from consolidated subsidiaries


(69,404
)






90,270



4,600



(4,600
)


20,866



(65,704
)






121,626



6,889



(6,889
)


55,922Discontinued operations, net of tax










2,292











2,292











2,291











2,291(Loss) income before equity earnings from consolidated
    subsidiaries


(69,404
)






92,562



4,600



(4,600
)


23,158



(65,704
)






123,917



6,889



(6,889
)


58,213Equity in earnings from consolidated subsidiaries


92,562















(92,562
)






123,917















(123,917
)


Net income (loss)

$
23,158


$



$
92,562


$
4,600


$
(97,162
)

$
23,158


$
58,213


$



$
123,917


$
6,889


$
(130,806
)

$
58,213  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 OPERATIONS
  Year Ended December 31, 2007Investment inGuarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


Total(In thousands)Revenue:Natural gas sales

$



$



$
518,431


$



$



$
518,431Natural gas liquids sales










491,432











491,432Transportation, compression and processing fees










22,306











22,306Condensate and other










32,346











32,346Total revenue










1,064,515











1,064,515Costs and expenses:Cost of natural gas and natural gas liquids










853,969











853,969Transportation










5,948











5,948Operations and maintenance


1,764







38,942











40,706Depreciation and amortization


34







39,841











39,875General and administrative


10,848







23,790











34,638Taxes other than income










2,637











2,637Equity in earnings from unconsolidated affiliates










(2,850
)


(2,850
)


2,850



(2,850
)Total costs and expenses


12,646







962,277



(2,850
)


2,850



974,923Operating (loss) income


(12,646
)






102,238



2,850



(2,850
)


89,592Other income (expense):Interest and other income


247







2,607











2,854Gain on retirement of unsecured debt






















Interest and other financing costs


(29,467
)






116











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


(41,866
)






104,961



2,850



(2,850
)


63,095Provision for income taxes


(1,714
)


















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


(43,580
)






104,961



2,850



(2,850
)


61,381Discontinued operations, net of tax










1,794











1,794(Loss) income equity in earnings from consolidated subsidiaries


(43,580
)






106,755



2,850



(2,850
)


63,175Equity in earnings from consolidated subsidiaries


106,755















(106,755
)


Net income (loss)

$
63,175


$



$
106,755


$
2,850


$
(109,605
)

$
63,175  F-31




---



##### 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, 2009


Year Ended December 31, 2008Investment 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 provided by (used in) operating activities

$
25,217


$



$
116,101


$
20,931


$
(20,931
)

$
141,318


$
(155,565
)

$



$
245,489


$
22,460


$
(22,460
)

$
89,924Cash Flows From Investing Activities:Additions to property, plant and equipment










(73,232
)










(73,232
)










(152,533
)










(152,533
)Acquisitions, net of cash acquired










(2,840
)










(2,840
)










(12,655
)










(12,655
)Investment in consolidated subsidiaries


(105
)














105







(22,990
)














22,990



Distributions from consolidated subsidiaries


47,675















(47,675
)






89,000















(89,000
)


Proceeds from sale of assets










6,061











6,061











28











28Other










(956
)


4,526



(4,526
)


(956
)










(33,695
)


(23,463
)


23,463



(33,695
)Net cash provided by (used in) investing activities


47,570







(70,967
)


4,526



(52,096
)


(70,967
)


66,010







(198,855
)


(23,463
)


(42,547
)


(198,855
)Cash Flows From Financing Activities:Proceeds from long-term debt


70,000



















70,000



579,000



















579,000Repayments of long-term debt


(20,000
)


















(20,000
)


(339,000
)


















(339,000
)Retirement of Senior Notes


(14,286
)


















(14,286
)


(34,313
)


















(34,313
)Distributions to unitholders


(125,721
)


















(125,721
)


(104,234
)


















(104,234
)Contributions from parent










105







(105
)














22,990







(22,990
)


Distributions to parent










(47,675
)






47,675















(89,000
)






89,000



Other


664











4,227



(4,227
)


664



( 1,499
)






(4
)


26,833



(26,833
)


(1,503
)Net cash (used in) provided by financing activities


(89,343
)






(47,570
)


4,227



43,343



(89,343
)


99,954







(66,014
)


26,833



39,177



99,950Net (decrease) increase in cash and cash equivalents


(16,556
)






(2,436
)


29,684



(29,684
)


(18,992
)


10,399







(19,380
)


25,830



(25,830
)


(8,981
)Cash and cash equivalents, beginning of year


20,417







43,267



30,212



(30,212
)


63,684



10,018







62,647



4,382



(4,382
)


72,665Cash and cash equivalents, end of year

$
3,861


$



$
40,831


$
59,896


$
(59,896
)

$
44,692


$
20,417


$



$
43,267


$
30,212


$
(30,212
)

$
63,684  F-32




---



##### 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, 2007Investment inGuarantor


Non-GuarantorParent


Co-Issuer


Subsidiaries


Subsidiaries


Eliminations


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

$
(19,109
)

$



$
147,327


$
3,706


$
(3,706
)

$
128,218Cash Flows From Investing Activities:Additions to property, plant and equipment










(80,898
)










(80,898
)Acquisitions, net of cash acquired










(641,097
)










(641,097
)Investment in consolidated subsidiaries


(679,066
)














679,066



Distributions from consolidated subsidiaries


73,398















(73,398
)


Other










(5,057
)


(1,051
)


1,051



(5,057
)Net cash (used in) provided by investing activities


(605,668
)






(727,052
)


(1,051
)


606,719



(727,052
)Cash Flows From Financing Activities:Proceeds from long-term debt


663,781



















663,781Repayments of long-term debt


(288,000
)


















(288,000
)Distributions to unitholders


(73,629
)


















(73,629
)Proceeds from private placement of common units


157,125



















157,125Proceeds from private placement of Class E units


177,875



















177,875Contributions from parent










679,066







(679,066
)


Distributions to parent










(73,398
)






73,398



Other


(3,643
)






(1,494
)


1,727



(1,727
)


(5,137
)Net cash provided by (used in) financing activities


633,509







604,174



1,727



(607,395
)


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


8,732







24,449



4,382



(4,382
)


33,181Cash and cash equivalents, beginning of year


1,286







38,198











39,484Cash and cash equivalents, end of year

$
10,018


$



$
62,647


$
4,382


$
(4,382
)

$
72,665  F-33




---



##### Table of Contents



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

Amount2010

$
2011


2012


270,0002013


2014


Thereafter


582,190$
852,190   Note 8 
    Members
    Capital  Common
    Units
  two-for-one two-for-one
  Class C
    Units
    Class D
    Units
  one-for-one
  Class E
    Units
    Subordinated
    Units
  one-for-one
 F-34




---



##### Table of Contents



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











     Distributions
    DistributionQuarter Ending

Per unit


Date Declared


Record Date


Payment Date


AmountDecember 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



31,466,000March 31, 2009


0.5750



April 15, 2009



May 1, 2009



May 15, 2009



31,748,000June 30, 2009


0.5750



July 15, 2009



August 3, 2009



August 13, 2009



31,871,000September 30, 2009


0.5750



October 14, 2009



November 2, 2009



November 12, 2009



31,860,000December 31, 2009


0.5750



January 13, 2010



February 1, 2010



February 11, 2010



31,911,000     (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
   F-35




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)    Restricted Common Units.
    2009


2008


2007Weighted





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 year


169,769


$
22.35



241,181


$
22.92



315,936


$
20.84Granted


18,000



18.85



18,000



12.61



23,500



37.20Vested


(76,782
)


22.39



(89,122
)


21.94



(93,742
)


19.56Vested-not released










395



20.25







Forfeited


(5,486
)


27.67



(685
)


20.95



(4,513
)


21.09Outstanding at end of year


105,501


$
21.45



169,769


$
22.35



241,181


$
22.92     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)    2009


2008


2007Weighted





Weighted





WeightedAverage





Average





AverageNumber of


Grant-


Number of


Grant-


Number of


Grant-Phantom


Date Fair


Phantom


Date Fair


Phantom


Date FairUnits


Value


Units


Value


Units


ValueOutstanding at beginning of year


588,910


$
34.18



100,795


$
40.81






$
Granted


225,700



15.39



532,248



32.40



101,465



40.82Vested


(41,769
)


38.43



(39,477
)


26.55







Vested-not released


(450
)


38.78



450



38.78







Cancelled


(11,941
)


17.49















Forfeited


(62,314
)


30.61



(5,106
)


38.06



(670
)


41.74Outstanding at end of year


698,136


$
28.46



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)    2009


2008


2007Number 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 year


1,411,006


$
23.78



1,442,847


$
22.60



1,212,506


$
17.15Granted


33,000



14.89



191,500



32.05



418,200



37.60Exercised


(61,782
)


10.75



(71,722
)


15.74



(115,288
)


15.72Cancelled


(19,864
)


28.87



(37,040
)


14.79







Forfeited


(59,884
)


28.95



(114,579
)


30.62



(72,571
)


29.92Outstanding at end of year


1,302,476


$
23.86



1,411,006


$
23.78



1,442,847


$
22.60Aggregate intrinsic value at end of year

$
5,430,000






$
453,000






$
19,843,000Weighted average remaining contractual term


6.5 years







7.4 years







8.1 yearsExercisable Options:Outstanding at end of year


783,031


$
20.65



556,866


$
18.60



362,645


$
15.43Aggregate intrinsic value at end of year

$
4,493,000






$
329,000






$
7,585,000Weighted average remaining contractual term


5.9 years







6.7 years







7.5 yearsWeighted average fair value of option granted





$
2.07






$
3.00






$
4.33Options expected to vest:At end of year


1,172,228


$
23.86



1,269,905


$
23.78



1,298,562


$
22.60Aggregate intrinsic value at end of year

$
4,887,000






$
408,000






$
17,859,000Weighted average remaining contractual term


6.5 years







7.4 years







8.1 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 31,2009


2008


2007Weighted average exercise price

$
14.89


$
32.05


$
37.60Expected volatility


29.8-32.3
%


20.0-20.7
%


20.6-21.5
%Distribution yield


6.68-6.99
%


6.18-6.59
%


6.00-6.10
%Risk-free interest rate


1.71-3.28
%


1.76-3.94
%


3.48-5.11
%Expected term (in years)


6.5



6.5



6.5Weighted average grant-date fair value of options granted

$
2.07


$
3.00


$
4.33Total intrinsic value of options exercised

$
508,000


$
1,117,000


$
2,361,000     Unit Appreciation Rights.
    Number of


WeightedUnits


AverageUnderlying UARs


Exercise PriceOutstanding at beginning of year





$
Granted


320,000



15.38Forfeited


(17,100
)


15.09Outstanding at end of year


302,900


$
15.40     Year EndedDecember 31,2009Weighted average exercise price

$
15.40Expected volatility


30.8%-64.8
%Distribution yield


6.76%-8.47
%Risk-free interest rate


0.90%-3.18
%Expected term (in years)


1.8  5.8Weighted average grant-date fair value of appreciation rights
    granted

$
3.01Total intrinsic value of appreciation rights exercised

$
    F-39




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 8 
    Members
    Capital (Continued)  Unit Awards.
  Accounting
    for Certain Financial Instruments With Characteristics of Both
    Liabilities and Equity
    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 31,2009


2008


2007Affiliates of
    Mr. Eckel:(1)Natural gas
    sales(2)

$
3


$
113


$
31Gathering and compression
    services(4)


18



22



30Natural gas
    purchases(6)


1,070



1,426



2,251Payable by us as of December 31, 2009 and
    2008(7)


147



199Webb Duval:Natural gas
    sales(2)


923



590



Natural gas
    purchases(6)


562



2,542



955Transportation
    costs(8)


334



379



357Management
    fees(9)


221



216



211Reimbursable
    costs(9)


614



654



522Payable to us as of December 31, 2009 and
    2008(10)


910



287Payable by us as of December 31, 2009 and
    2008(7)


321



80Southern Dome:Natural gas liquid
    sales(3)










302Condensate
    sales(5)










145Management
    fees(9)


250



250



250Reimbursable
    costs(9)


328



599



448Payable to us as of December 31, 2009 and
    2008(10)


586



89Bighorn:(11)Compressor rental
    fees(5)


981







Gathering
    costs(8)


309



603



166Natural gas
    purchases(6)


25



30



Management
    fees(9)


357



287



115Reimbursable
    costs(9)


3,121



252



49Payable to us as of December 31, 2009 and
    2008(10)


490



2,109Payable by us as of December 31, 2009 and
    2008(7)


23



45Fort Union:(11)Gathering
    costs(8)


8,259



8,440



2,110Treating
    costs(6)


199



856



125Management
    fees(9)


212







Reimbursable
    costs(9)


1,419



95



22Payable to us as of December 31, 2009 and
    2008(10)


634



269Payable by us as of December 31, 2009 and
    2008(7)


162



175Other:(12)Natural gas
    sales(2)


270



423



212Natural gas liquid
    sales(5)


3







Payable to us as of December 31, 2009 and
    2008(10)


137



199     (1)
    
    These entities were controlled by Mr. Eckel until his death
    in November 2009, and since that time have been controlled by
    Mr. Lawing.(2)
    
    Revenues included in natural gas sales on our consolidated
    statements of operations. F-41




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 9 
    Related
    Party Transactions (Continued)   (3)
    
    Revenues included in natural gas liquids sales on our
    consolidated statements of operations.(4)
    
    Revenues included in transportation, compression and processing
    fees on our consolidated statements of operations.(5)
    
    Revenues included in condensate and other on our consolidated
    statements of operations.(6)
    
    Included in costs of natural gas and natural gas liquids on our
    consolidated statements of operations.(7)
    
    Included in accounts payable on the consolidated balance sheets.(8)
    
    Costs included in transportation on our consolidated statements
    of operations.(9)
    
    Management fees and reimbursable costs received from our
    unconsolidated affiliates consists of the total compensation
    paid to us by our unconsolidated affiliates and is included in
    general and administrative expenses on our consolidated
    statements of operations.(10)
    
    Included in accounts receivable on the consolidated balance
    sheets.(11)
    
    The results for 2007 include the period from October 1,
    2007 through December 31, 2007.(12)
    
    The results for 2007 include the period from May 1, 2007
    through December 31, 2007.    Other
    Transactions
    Note 10 
    Customer
    Information    Percentage
    of Consolidated
    Revenue(1)
  Year Ended December 31,Customer

Segment


2009


2008


2007ONEOK Energy Services, L.P.


Oklahoma



16
%


16
%


16
%ONEOK Hydrocarbon, L.P.


Oklahoma



17
%


13
%


14
%DCP Midstream, L.L.C.


Texas and Oklahoma



12
%


(1
)


(1
)Kinder Morgan


Texas



(1
)


(1
)


10
%Enterprise Products Operating, L.P.


Texas



(1
)


14
%


20
%  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


2009


2008


2007New Dominion LLC


Oklahoma



16
%


13
%


18
%Altex Resources, Inc.


Oklahoma



12
%


(1
)


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

Segment


2009


2008


2007ONEOK Energy Services, L.P.


Oklahoma



17
%


15
%


18
%ONEOK Hydrocarbon, L.P.


Oklahoma



21
%


(1
)


13
%DCP Midstream, L.L.C.


Texas and Oklahoma



20
%


(1
)


(1
)Enterprise Products Operating, L.P.


Texas



(1
)


(1
)


10
%Kinder Morgan


Texas



(1
)


11
%


(1
)The Goldman Sachs Group, Inc.


Texas



(1
)


10
%


(1
)     (1)
    
    Percentages are not provided for periods for which the customer
    or producer is less than 10% of our consolidated revenue.  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)  over-the-counter
      mark-to-market
    Purchased
    Houston Ship Channel Index Natural Gas Options
  Call Spread

CallCall Strike

Call Volumes

Strike

Volume(Per MMBtu)

(MMBtu/d)

(Per MMBtu)

(MMBtu/d)Bought

Sold2010

$
7.3500


$
10.0000



7,100


$
10.0000



10,0002011

$
6.9500


$
10.0000



7,100


$
10.0000



10,000  F-44




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)  Purchased
    Houston Ship Channel Index Natural Gas Basis Swap
  SwapStrike

Volume(per MMbtu)

(MMbtu/d)2010

$
0.0450



10,000   Sold
    Centerpoint East Index Natural Gas Basis Swap
  SwapStrike

Volume(per MMbtu)

(MMbtu/d)2010

$
0.0230



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)2010

$
0.5550



1,600


$
0.5700



5002011

$
0.5300



1,700


$
0.5450



5002011

$
0.5300



500







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


SwapStrike


Volumes


Price


Volumes(Per gallon)


(Bbls/d)


(Per gallon)


(Bbls/d)2010

$
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

Volumes(Per gallon)

(Bbls/d)Bought

Sold2010

$
1.4900


$
0.8500



1,1002010

$
1.4900


$
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)2010

$
1.0350



300







2010

$
1.1145



100


$
1.2025



1002011

$
1.0205



300







2011

$
1.1100



100


$
1.1800



1002011

$
1.7100



200







  F-45




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)  Purchased
    Mt. Belvieu Non-TET Isobutane Put Spread Options
  Put SpreadStrike

Volumes(Per gallon)

(Bbls/d)Bought

Sold2010

$
1.8900


$
1.1145



1002010

$
1.8900


$
1.0350



300   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)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

Volumes(Per gallon)

(Bbls/d)Bought

Sold2010

$
1.88


$
1.1000



2002010

$
1.88


$
1.0300



300   Purchased
    Mt. Belvieu Non-TET Natural Gasoline Puts
  PutStrike

Volumes(Per gallon)

(Bbls/d)2010

$
1.408



3002011

$
1.410



300   Purchased
    Mt. Belvieu Non-TET Natural Gasoline Put Spread
    Options
  Put SpreadStrike

Volumes(Per gallon)

(Bbls/d)Bought

Sold2010

$
2.54


$
1.408



300  F-46




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)  Purchased
    WTI Crude Oil Puts
  PutStrike


Volumes(Per barrel)


(Bbls/d)2010

$
55.00



1,0002010

$
60.00



4002011

$
55.00



1,000
(1)2011

$
60.00



4002011

$
77.00



7002011

$
79.00



4002012

$
79.00



300     (1)
    
    Instrument is not designated as a cash flow hedge under hedge
    accounting.  Purchased
    WTI Crude Oil Put Spread Options
  Put SpreadStrike

Volumes(Per barrel)

(Bbls/d)Bought

Sold2010

$
118.00


$
55.00



1,0002010

$
118.00


$
60.00



400   Interest
    Rate Risk Hedging Program
    mark-to-market
    FASB
    ASC 820 Fair Value Measurement (SFAS No. 157) and
    FASB ASC 815 Disclosures about Derivative Instruments and
    Hedging Activities (SFAS No. 161)
   F-47




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)    
    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; and
    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 Hedging
    Instruments(a)
  December 31, 2009


December 31, 2008Level 1


Level 2


Level 3


Total


Level 1


Level 2


Level 3


Total(In thousands)AssetsCommodity derivatives:Short-term 
    Designated(b)

$



$



$
36,588


$
36,588


$



$



$
76,440


$
76,440Short-term  Not
    designated(b)






27







27















Long-term 
    Designated(c)










14,805



14,805











81,192



81,192Long-term  Not
    designated(c)










576



576











1,700



1,700Total

$



$
27


$
51,969


$
51,996


$



$



$
159,332


$
159,332LiabilitiesCommodity derivatives:Short-term 
    Designated(d)

$



$



$
4,763


$
4,763


$



$



$



$
Short-term  Not
    designated(d)


























2,308



2,308Long-term 
    Designated(e)










4,600



4,600











4,347



4,347Interest rate derivatives:Short-term 
    Designated(d)






















302







302Short-term  Not
    designated(d)






4,909







4,909







3,662







3,662Long-term  Designated(e)






















854







854Long-term  Not
    designated(e)






3,238







3,238







6,288







6,288Total

$



$
8,147


$
9,363


$
17,510


$



$
11,106


$
6,655


$
17,761Total designated

$



$



$
42,030


$
42,030


$



$
(1,156
)

$
153,285


$
152,129Total not designated

$



$
(8,120
)

$
576


$
(7,544
)

$



$
(9,950
)

$
(608
)

$
(10,558
)     (a)
    
    Instruments re-measured on a recurring basis.(b)
    
    Included on the consolidated balance sheets as a current asset
    under the heading of Risk management assets. F-48




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)   (c)
    
    Included on the consolidated balance sheets as a noncurrent
    asset under the heading of Risk management assets.(d)
    
    Included on the consolidated balance sheets as a current
    liability under the heading of Risk management
    liabilities.(e)
    
    Included on the consolidated balance sheets as a noncurrent
    liability under the heading of Risk management and other
    noncurrent liabilities.        Year Ended December 31,2009


2008(In thousands)Assets (liability) balance, beginning of year

$
152,677


$
(48,407
)Total gains or losses:Noncash amortization of option premium


(36,950
)


(32,842
)Other amounts included in earnings


72,669



5,206Included in accumulated other comprehensive loss


(84,021
)


176,593Purchases


6,940



60,160Settlements


(68,709
)


(8,033
)Transfers in and/or out of Level 3






Asset balance, end of year

$
42,606


$
152,677Change in unrealized losses (income) included in earnings
    related to instruments still held as of the end of the year

$
4,653


$
(3,246
)     and/or
 F-49




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 11 
    Risk
    Management Activities (Continued)      The Effect of Derivative Instruments on the Statements of
    OperationsAmount of Gain (Loss)Amount of Gain (Loss)


Recognized in IncomeDerivatives in

Amount of Gain (Loss)


Reclassified from


on DerivativeFASB ASC 815

Recognized in OCI on


Accumulated OCI into


(Ineffective Portion and(SFAS 133) Cash Flow

Derivatives (Effective


Income (Effective


Amount Excluded fromHedging  Relationships

Portion)


Portion)


Effectiveness Testing)


Statements of Operations Location(In thousands)Year ended December 31, 2009Natural gas

$
3,637


$
(3,401
)

$



Natural gas salesNatural gas liquids


26,123



31,204



(122
)

Natural gas liquids salesCrude oil


12,365



14,093



(416
)

Condensate and otherInterest rate swaps


(515
)


304






Interest and other financing costsTotal

$
41,610


$
42,200


$
(538
)     The Effect of Derivative Instruments on the Statements of
    OperationsAmount of Gain (Loss)Recognized in Income onDerivatives Not Designated as Hedging Instruments Under (FASB
    ASC 815 SFAS 133)

Derivative


Statement of Operations Location(In thousands)Year ended December 31, 2009Natural gas

$
27


Natural gas salesNatural gas liquids


4,643


Natural gas liquids salesInterest rate


2,748


Interest and other financing costsTotal

$
7,418    Note 12 
    Fair
    Value of Financial Instruments    December 31,2009


2008Carrying


Estimated


Carrying


EstimatedValue


Fair Value


Value


Fair Value(In thousands)Cash and cash equivalents

$
44,692


$
44,692


$
63,684


$
63,684Credit Facility


270,000



260,348



220,000



220,0002016 Notes


332,665



337,655



332,665



226,2122018 Notes


249,525



251,936



267,750



170,021   F-50




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 13 
    Commitments
    and Contingencies  Commitments
  2010 2011 2012 2013 2014
          Regulatory
    Compliance
    Litigation
   F-51




---



##### 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 31,2009

2008

2007(In thousands)Cash payments for interest, net of $3,362,000, $3,471,000 and
    $932,000 capitalized in 2009, 2008 and 2007, respectively

$
53,475


$
49,205


$
24,471Cash payments for federal and state income taxes

$
762


$
492


$
     Note 15 
    Discontinued
    Operations   F-52




---



##### Table of Contents



COPANO
    ENERGY, L.L.C. AND SUBSIDIARIES
  NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS  (Continued)
   Note 15 
    Discontinued
    Operations (Continued)    December 31,2009


2008Prepayment and other current assets

$



$
113Property, plant and equipment, net






4,475Intangibles, net






633Other assets, net






343



5,564Other current liabilities






Net assets

$



$
5,564   Year Ended December 31,2009


2008


2007Crude oil sales

$
62,302


$
174,667


$
77,142Cost of crude oil purchases


58,935



171,401



74,814Income from discontinued operations before taxes

$
2,292


$
2,291


$
1,794Income tax expense










Net income from discontinued operations

$
2,292


$
2,291


$
1,794    Note 16 
    Segment
    Information    
    Oklahoma, which includes midstream natural gas services in
    central and east Oklahoma, including gathering of natural gas
    and related services such as compression, dehydration, treating,
    processing and nitrogen rejection. This segment includes our
    equity investment in Southern Dome and, through September 2009,
    included a crude oil pipeline.
    Texas, which includes midstream natural gas services in south
    and north Texas, including gathering and intrastate transmission
    of natural gas, and related services such as compression,
    dehydration, treating, conditioning or processing and marketing.
    Our Texas segment also provides NGL fractionation and
    transportation. Our Texas segment includes our Louisiana
    processing assets and our equity investment in Webb Duval.
    Rocky Mountains, which includes natural gas gathering and
    treating services in Wyoming. Our Rocky Mountains segment
    includes our equity investments in Bighorn and Fort Union,
    two firm gathering agreements with Fort Union and two firm
    transportation agreements with WIC.     F-53




---



##### Table of Contents



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


Total


Corporate andOklahoma(a)


Texas


Mountains


Segments


Other


ConsolidatedYear Ended December 31, 2009:Total segment gross margin

$
76,686


$
103,620


$
3,254


$
183,560


$
35,890


$
219,450Operations and maintenance expenses


23,469



27,960



48



51,477







51,477Depreciation, amortization and impairment


31,698



20,868



2,920



55,486



1,489



56,975General and administrative expenses


8,087



9,453



2,551



20,091



19,420



39,511Taxes and other income


1,998



1,698



18



3,714



18



3,732Equity in (earnings) loss from unconsolidated affiliates


(1,768
)


60



(2,892
)


(4,600
)






(4,600
)Operating income

$
13,202


$
43,581


$
609


$
57,392


$
14,963


$
72,355Natural gas sales

$
165,524


$
147,218


$
5,181


$
317,923


$
(1,237
)

$
316,686Natural gas liquids sales


171,018



206,485







377,503



29,159



406,662Transportation, compression and processing fees


6,774



28,161



21,048



55,983







55,983Condensate and other


26,617



5,149



981



32,747



7,968



40,715Sales to external customers

$
369,933


$
387,013


$
27,210


$
784,156


$
35,890


$
820,046Intersegment sales

$
(966
)

$
966


$



$



$



$
Interest and other financing costs

$



$



$



$



$
55,836


$
55,836Segment assets


721,091



439,375



694,710



1,855,176



12,236



1,867,412Year Ended December 31, 2008:Total segment gross margin

$
133,112


$
142,723


$
5,877


$
281,712


$
(27,568
)

$
254,144Operations and maintenance expenses


23,874



29,950







53,824







53,824Depreciation, amortization and impairment


30,360



15,770



5,521



51,651



1,265



52,916General 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

$
72,646


$
87,082


$
629


$
160,357


$
(54,654
)

$
105,703Natural gas sales

$
344,045


$
382,189


$
21,812


$
748,046


$
(788
)

$
747,258Natural gas liquids sales


280,046



345,810







625,856



(27,870
)


597,986Transportation, compression and processing fees


2,570



32,912



23,524



59,006







59,006Condensate and other


40,880



6,931



1,268



49,079



1,090



50,169Sales to external customers

$
667,541


$
767,842


$
46,604


$
1,481,987


$
(27,568
)

$
1,454,419Intersegment sales

$
(1,991
)

$
1,991


$



$



$



$
Interest and other financing costs

$



$



$



$



$
64,978


$
64,978Segment assets


727,875



397,788



711,434



1,837,097



176,568



2,013,665Year Ended December 31, 2007:Total segment gross margin

$
112,763


$
121,935


$
1,145


$
235,843


$
(31,245
)

$
204,598Operations and maintenance expenses


20,261



20,437



8



40,706







40,706Depreciation, amortization and impairment


25,632



12,749



670



39,051



824



39,875General 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

$
60,727


$
72,916


$
(256
)

$
133,387


$
(43,795
)

$
89,592Natural gas sales

$
256,541


$
256,085


$
3,586


$
516,212


$
2,219


$
518,431Natural gas liquids sales


224,832



296,754







521,586



(30,154
)


491,432Transportation, compression and processing fees


667



16,044



5,595



22,306







22,306Condensate and other


30,186



5,470







35,656



(3,310
)


32,346Sales to external customers

$
512,226


$
574,353


$
9,181


$
1,095,760


$
(31,245
)

$
1,064,515 F-54




---



##### Table of Contents



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


Total


Corporate andOklahoma(a)


Texas


Mountains


Segments


Other


ConsolidatedIntersegment sales

$
(400
)

$
400


$



$



$



$
Interest and other financing costs

$



$



$
103


$
103


$
29,248


$
29,351     (a)
    
    All information excludes the results of discontinued operations
    for the sale of the crude oil pipeline and related assets
    discussed in Note 15 except for the information
    related to intersegment sales, interest and other financing
    costs and net income (loss).   Note 17 
    Quarterly
    Financial Data (Unaudited)  Year 2009Quarter EndedMarch 31


June 30


September 30


December 31


Year(In thousands, except per unit information)Revenue

$
201,078


$
180,183


$
189,531


$
249,254


$
820,046Operating income


15,971



18,033



18,146



20,205



72,355Net income


5,905



6,038



3,729



7,486



23,158Discontinued operations, net of tax


561



570



262



899



2,292Basic net income per common unit


0.11



0.11



0.07



0.14



0.43Diluted net income per common unit


0.10



0.10



0.06



0.13



0.40   Year 2008Quarter EndedMarch 31


June 30


September 30


December 31


Year(In thousands, except per unit information)Revenue

$
360,565


$
444,096


$
402,871


$
246,888


$
1,454,419Operating income


24,995



38,043



23,872



18,793



105,703Net income


14,502



23,202



8,723



11,786



58,213Discontinued operations, net of tax


726



1,323



161



81



2,291Basic net income per common unit


0.31



0.49



0.18



0.22



1.20Diluted net income per common unit


0.25



0.40



0.15



0.21



1.01   F-55