10-K 1 h54400e10vk.htm FORM 10-K e10vk
 

 
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 1934
    For the fiscal year ended December 31, 2007
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For 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 Registered
Common Units Representing Limited
Liability Company Interests
  The NASDAQ Stock Market LLC
 
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
 
Title of Class
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
As of June 30, 2007, the aggregate market value of our voting and non-voting common equity held by non-affiliates of the registrant was approximately $1.598 billion based on $42.67 per common unit, the closing price of our common units as reported on The NASDAQ Stock Market LLC on June 29, 2007.
 
As of February 15, 2008, 47,378,159 of our common units were outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
     
Document
 
Parts Into Which Incorporated
Portions of the Proxy Statement for the Annual Meeting of Unitholders of
Copano Energy, L.L.C. to be held May 15, 2008
  Part III
 


 

 
TABLE OF CONTENTS
 
                 
        Page
 
PART I
 
Item 1.
    Business     1  
 
Item 1A.
    Risk Factors     26  
 
Item 1B.
    Unresolved Staff Comments     41  
 
Item 2.
    Properties     41  
 
Item 3.
    Legal Proceedings     42  
 
Item 4.
    Submission of Matters to a Vote of Security Holders     42  
 
PART II
 
Item 5.
    Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities     43  
 
Item 6.
    Selected Financial Data     47  
 
Item 7.
    Management’s Discussion and Analysis of Financial Condition and Results of Operation     51  
 
Item 7A.
    Quantitative and Qualitative Disclosures about Market Risk     72  
 
Item 8.
    Financial Statements and Supplementary Data     78  
 
Item 9.
    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     78  
 
Item 9A.
    Controls and Procedures     78  
 
Item 9B.
    Other Information     82  
 
PART III
 
Item 10.
    Directors and Executive Officers of the Registrant     83  
 
Item 11.
    Executive Compensation     83  
 
Item 12.
    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters     83  
 
Item 13.
    Certain Relationships and Related Parties     83  
 
Item 14.
    Principal Accountant Fees and Services     83  
 
PART IV
 
Item 15.
    Exhibits and Financial Statement Schedules     84  
 
FINANCIAL STATEMENTS
Copano Energy, L.L.C. Index to Financial Statements
    F-1  


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PART I
 
Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C. and its wholly owned subsidiaries.
 
As used generally in the energy industry and in this Annual Report, the following terms have the meanings indicated below. Please read the subsection of Item 1 captioned “— Industry Overview” for a discussion of the midstream natural gas industry.
 
     
/d:
  Per day
$/gal:
  U.S. dollars per gallon
Bbls:
  Barrels
Bcf:
  One billion cubic feet
Btu:
  British thermal units
MMBtu:
  One million British thermal units
Mcf:
  One thousand cubic feet
NGLs:
  Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
residue gas:
  The pipeline quality natural gas remaining after natural gas is processed
Tcf:
  One trillion cubic feet
throughput:
  The volume of product transported or passing through a pipeline, plant, terminal or other facility
 
Item 1.   Business
 
The following discussion of our business segments provides information regarding our principal natural gas processing plants, pipelines and other assets. For a discussion of our results of operations, including throughput and processing rates, please read Item 7 of this report, captioned “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
 
General
 
We are a growth-oriented midstream energy company engaged in the business of providing comprehensive services to natural gas producers, including natural gas gathering, compression, dehydration, treating, transportation, processing and conditioning. Our assets are primarily located in Oklahoma, Texas, and Wyoming and include approximately 6,000 miles of active natural gas gathering and transmission pipelines and six natural gas processing plants, with over one billion cubic feet per day, or Bcf/d, of combined processing capacity. In addition to our natural gas pipelines, we operate 150 miles of NGL pipelines and a 67-mile crude oil pipeline. We own some of our assets through our interests in entities partially owned by third parties, including approximately 600 miles of natural gas pipelines and the Southern Dome plant.
 
We were formed in August 2001 as a Delaware limited liability company to acquire entities operating under the Copano name since 1992. We completed our initial public offering, or IPO, on November 15, 2004. From our inception in 1992, we have grown through a combination of more than 40 acquisitions and organic growth projects, including approximately $1.3 billion in acquisitions completed since our IPO. Our common units are listed on The NASDAQ Stock Market LLC under the symbol “CPNO.”
 
Recent Developments
 
Declaration of Distribution.  On January 16, 2008, our Board of Directors declared a cash distribution for the three months ended December 31, 2007 of $0.51 per unit for all outstanding common units. The distribution, totaling $24.2 million, was paid on February 14, 2008 to holders of record at the close of business on February 1, 2008.
 
Hedge Activity.  In January 2008, we purchased puts for ethane, propane, iso-butane, normal butane and West Texas Intermediate crude oil at strike prices reflecting current market conditions, and divested previously acquired


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put options on these products at lower strike prices. These transactions were conducted through two investment grade counterparties in accordance with our risk management policy and were designated as cash flow hedges to mitigate the impact of decreases in NGL prices. Our net costs for these transactions were approximately $15.6 million.
 
For a more detailed discussion of our risk management activities, please read “— Risk Management” and Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”
 
Public Offering of 81/8% Senior Notes due 2016 and Reduction of Credit Facility Debt.  On November 19, 2007, we closed an underwritten public offering of $125 million in principal amount of our 81/8% Senior Notes due 2016. The notes, sold at a premium to par, were an additional issuance under our indenture dated February 7, 2006 and were offered under our effective shelf registration statement. We used net proceeds from the offering of $124 million to reduce outstanding indebtedness under our senior secured revolving credit facility, and for general company purposes.
 
Cantera Acquisition.  We acquired Denver-based Cantera Natural Gas, LLC, or Cantera, on October 1, 2007, and closed the acquisition on October 19, 2007, for total consideration of $732.8 million, including working capital and other closing adjustments, consisting of $620.3 million in cash and 3,245,817 Class D units issued to the seller. We financed the cash consideration for the Cantera acquisition and related costs with borrowings of $300 million under our $550 million senior secured revolving credit facility and net proceeds from a $335 million private placement of 4,533,324 common units and 5,598,836 Class E units. The Cantera acquisition expanded our operations into the Rocky Mountains region. Cantera’s principal assets are its 51.0% and 37.04% managing member interests, respectively, in Bighorn Gas Gathering, L.L.C., or Bighorn, and Fort Union Gas Gathering, L.L.C., or Fort Union, two firm gathering agreements with Fort Union and two firm capacity transportation agreements with Wyoming Interstate Gas Company. Bighorn and Fort Union operate natural gas gathering systems in Wyoming’s Powder River Basin. At the time of the acquisition, the Bighorn system included approximately 238 miles of natural gas gathering pipelines, which deliver natural gas into the Fort Union system, and the Fort Union system consisted of an approximately 106-mile, 24” pipeline and a 62-mile loop. Cantera (now Copano Natural Gas/Rocky Mountains, L.L.C.), through its interests in Bighorn and Fort Union, is a leading gatherer of coal-bed methane gas in the Powder River Basin. Substantially all of Cantera’s, Bighorn’s and Fort Union’s contract portfolios consist of fixed-fee contracts, which has resulted in a significant increase in the fixed-fee component of our contract mix.
 
Amended and Restated Revolving Credit Facility.  On October 19, 2007 and in connection with the closing of the Cantera acquisition, we amended our senior secured revolving credit facility to, among other things, increase borrowing capacity under the credit facility from $200 million to $550 million and extend the maturity date to October 18, 2012. For a more detailed discussion of our credit facility, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Description of Our Indebtedness.”
 
Cimmarron Acquisition.  On May 1, 2007, we acquired Cimmarron Gathering, LP, or Cimmarron, for approximately $97.2 million, including working capital and other closing adjustments, consisting of $43.2 million in cash and 1,579,409 Class C units issued to the sellers. We funded the cash portion of the purchase price for Cimmarron with borrowings under our senior secured revolving credit facility. At the time of the acquisition, Cimmarron’s assets consisted primarily of approximately 430 miles of active natural gas gathering pipelines located primarily in central and eastern Oklahoma and in North Texas, of which approximately 69 miles were operated for crude oil gathering service, and included Cimmarron’s 70% undivided interest in the Tri-County gathering system. Cimmarron also owned approximately 3,572 miles of inactive pipelines held for potential future development. In addition, in connection with our Cimmarron acquisition, we acquired the remaining 30% interest in the Tri-County gathering system for $15.3 million in cash, funded with cash on hand and borrowings under our senior secured revolving credit facility.


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Business Strategy
 
Our management team is committed to exploiting new business opportunities associated with our existing assets, pursuing complementary acquisition and organic expansion opportunities, and managing our commodity risk exposure. Key elements of our strategy include:
 
  •  Pursuing growth from our existing assets.  In many cases, our pipelines and processing plants have excess capacity, which provides us with opportunities to increase throughput volume with minimal incremental costs. We seek to increase cash flow from our existing assets by aggressively marketing our services to producers to connect new supplies of natural gas and increase volumes and utilization of capacity.
 
  •  Pursuing complementary acquisitions and organic expansion opportunities.  We seek to use our acquisition and integration experience to continue to make complementary acquisitions of midstream assets in our operating areas that provide opportunities to expand either the acquired assets or our existing assets to increase utilization of capacity. We pursue acquisitions that we believe will allow us to capitalize on our existing infrastructure, personnel, and producer and customer relationships to strengthen our existing integrated package of services. Also, we seek to expand our assets where appropriate to meet increased demand for our midstream services.
 
  •  Reducing the sensitivity of our cash flows to commodity price fluctuations.  Because of the volatility of natural gas and NGL prices, we attempt to structure our contracts in a manner that allows us to achieve positive gross margins in a variety of market conditions. Generally, we pursue arrangements under which the fee for our services is sufficient to provide us with positive operating margins irrespective of commodity prices. For example, we pursue processing arrangements at our Houston Central plant providing that we may elect to condition natural gas for a fee when processing is economically unattractive.
 
In addition, our commodity risk management activities are designed to hedge our exposure to commodity price risk and allow us to meet our debt service, maintenance capital expenditure and similar requirements, and our distribution objectives, despite fluctuations in commodity prices. We intend to continue to manage our exposure to commodity prices in the future by entering into hedge transactions. Please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”
 
  •  Exploiting the operating flexibility of our assets.  We can modify the operation of our assets to maximize our cash flows. For example, our Houston Central plant has the ability to transition rapidly between processing and conditioning of natural gas, which provides us with significant benefits during periods when processing natural gas is not profitable. Also, our Houston Central and Paden plants each have ethane-rejection capability (the ability to reduce the ethane extracted from natural gas in processing), which we employ as market conditions warrant.
 
  •  Expanding our geographic scope into new regions where our growth strategy can be applied.  We pursue opportunities to acquire assets in new regions where we believe growth opportunities are attractive and our business strategies could be applied. For example, with the Cantera acquisition in October 2007, we expanded into the Rocky Mountains region, and with the acquisition of ScissorTail Energy in August 2005, we expanded our operations to pursue opportunities in Oklahoma.
 
Our Operations
 
Our natural gas pipelines collect natural gas from wellheads or designated points near producing wells and deliver these volumes to third-party pipelines, our processing plants, third-party processing plants, local distribution companies, power generation facilities and industrial consumers. Our processing plants take delivery of natural gas from our gathering systems as well as third-party pipelines, and we treat the natural gas as needed to remove contaminants and process or condition it to extract mixed NGLs. After treating and conditioning or processing, we deliver the residue gas primarily to third-party pipelines through plant interconnects and sell the NGLs, in some cases after separating the NGLs into select component NGL products, to third parties. In addition, we operate NGL pipelines and a crude oil pipeline.


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Our Operating Segments
 
Overview
 
We manage and operate our business in three geographic segments: Oklahoma, Texas and Rocky Mountains. Our operating segments are summarized in the following table:
 
Copano Energy Operating Segments
 
                                     
                    Year Ended
 
                    December 31, 2007  
        Pipeline Miles(1)
          Average
       
        /Number of
    Throughput/
    Throughput/
    Utilization
 
        Processing
    Inlet
    Inlet
    of
 
Segment
  Primary Assets   Plants     Capacity(2)(3)     Volumes(2)(3)     Capacity  
 
Oklahoma
  Natural Gas Pipelines     3,680       234,100       166,207       71 %
    Processing Plants(4)(5)     4       158,000       81,134       51 %
    Crude Oil Pipelines     69       3,960       3,600       91 %
Texas
  Natural Gas Pipelines(6)     1,853       945,300       365,939       38 %
    Processing Plants(7)     2       900,000       544,016       60 %
    NGL Pipelines(8)     150       30,900       17,090       55 %
Rocky Mountains
  Natural Gas Pipelines(9)     463       1,140,000       821,434       72 %
 
 
(1) Natural gas pipeline miles for Oklahoma and Texas exclude 2,996 miles and 576 miles, respectively, of inactive pipelines that are being held for potential future development.
 
(2) Many pipeline capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacity and/or other facility upgrades including, for example, larger dehydration capacity.
 
(3) Natural gas pipeline throughputs and inlet capacity are measured in Mcf/d. Crude oil and NGL pipeline throughputs are measured in Bbls/d.
 
(4) Includes the Southern Dome plant owned by Southern Dome, LLC, or Southern Dome, an unconsolidated limited liability company in which we own a majority interest. The plant is designed for operating capacity of 30,000 Mcf/d but is currently configured for 18,000 Mcf/d.
 
(5) In addition to transporting natural gas to our plants for processing, our Oklahoma segment delivers natural gas to six third-party plants in exchange for a portion of the product revenues. Average daily throughput volumes processed at third-party plants for our Oklahoma segment were 41,382 Mcf/d for the year ended December 31, 2007.
 
(6) Includes the 144-mile Webb/Duval system owned by Webb/Duval Gatherers, or Webb Duval, an unconsolidated partnership in which we hold a 62.5% interest.
 
(7) In addition to our Houston Central plant, our Texas segment includes a processing plant in Lake Charles, Louisiana, which we acquired as part of the Cantera acquisition. This plant, which has had no material operations since the acquisition, is managed by the personnel who manage our Texas operations.
 
(8) Includes our 46-mile Brenham NGL pipeline, which we lease from Kinder Morgan Texas Pipeline and expect to place into service in March 2008.
 
(9) Owned by Bighorn and Fort Union, in which we own 51.0% and 37.04% interests, respectively.
 
Oklahoma
 
Our Oklahoma segment operates in active natural gas producing areas in central and eastern Oklahoma and includes assets we acquired through our purchases of ScissorTail Energy, LLC, or ScissorTail, in August 2005 and Cimmarron in May 2007. These assets include:
 
  •  ten primarily low-pressure gathering systems occupying approximately 53,000 square miles;
 
  •  a crude oil pipeline; and
 
  •  four processing plants, one of which we own through our majority interest in Southern Dome.


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The following map represents our Oklahoma segment:
 
(OKLAHOMA MAP)


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The tables below provide summary descriptions of our Oklahoma pipeline systems and processing plants.
 
Oklahoma Pipelines
 
                                         
          Diameter of
          Year Ended December 31,2007  
    Length
    Pipe
    Throughput
    Average
    Utilization
 
    (miles)     (range)     Capacity(1)(2)     Throughput(1)(2)     of Capacity  
 
Natural Gas Pipelines:
                                       
Stroud
    778       2²- 16²       102,000       90,743       89 %
Osage
    549       2²- 8²       26,000       18,883       73 %
Milfay
    351       2²- 16²       15,000       13,389       89 %
Glenpool
    1,015       2²- 10²       23,000       9,704       42 %
Twin Rivers
    537       2²- 12²       16,000       11,182       70 %
Mountain(3)
    164       2²- 20²       42,000       18,971       45 %
Central Oklahoma(4)
    190       2²- 12²       4,100       3,132       76 %
Tomahawk(5)
    96       3²- 10²       6,000       204       3 %
                                         
Oklahoma Natural Gas Gathering
    3,680               234,100       166,207          
                                         
Crude Oil Pipeline(6)
    69       4²- 6²       3,960       3,600       91 %
 
 
(1) Many capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacity or other facility upgrades.
 
(2) Natural gas pipeline throughputs are measured in Mcf/d. Crude oil throughputs are measured in Bbls/d.
 
(3) The Mountain system consists of three systems: Blue Mountain, Cyclone Mountain and Pine Mountain.
 
(4) Excludes 2,996 miles of inactive pipelines held for potential future development. Data reported for our Central Oklahoma system is only for the period from May 1, 2007 (the date of our Cimmarron acquisition) through December 31, 2007.
 
(5) The Tomahawk system was activated in April 2007 and is expected to be operational in March 2008.
 
(6) Data reported for our crude oil pipeline is only for the period from May 1, 2007 (the date of our Cimmarron acquisition) through December 31, 2007.
 
Oklahoma Processing
 
                                                 
                  Year Ended December 31, 2007  
                  Average
    Utilization
    Average Processing
 
    Associated
      Throughput
    Inlet
    of
    Volumes  
Processing Plants
  Gathering System   Facilities   Capacity(1)     Volumes(1)     Capacity     NGLs     Residue  
 
Paden
  Stroud   Cryogenic/refrigeration     100,000       54,347       54 %     8,044       42,042  
    Tomahawk   Ethane rejection                                        
        Nitrogen rejection(3)                                        
Milfay
  Milfay   Propane refrigeration     15,000       12,428       83 %     796       10,632  
Glenpool
  Glenpool   Cryogenic     25,000       9,266       37 %     508       9,314  
Southern Dome(2)
  Southern Dome   Propane refrigeration     18,000       5,093       28 %     244       4,706  
                                                 
Oklahoma Processing
            158,000       81,134       52 %     9,592       66,694  
                                                 
 
 
(1) Throughput capacity and inlet volumes are measured in Mcf/d. NGL volumes are measured in Bbls/d. Residue volumes are measured in MMBtu/d.
 
(2) We hold a majority interest in Southern Dome, which owns the Southern Dome plant. The plant is designed for operating capacity of 30,000 Mcf/d but is currently configured for 18,000 Mcf/d.


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(3) Nitrogen rejection capability at our Paden plant is expected to become operational in March 2008 and will be limited to 60,000 Mcf/d.
 
In addition to transporting natural gas to our plants for processing, our Oklahoma segment delivers natural gas to six third-party plants in exchange for a portion of the product revenues. Average daily volumes processed at third-party plants for our Oklahoma segment were 41,382 Mcf/d for the year ended December 31, 2007.
 
Stroud System and Paden Processing Plant
 
The Stroud system is located in Payne, Lincoln, Oklahoma, Pottawatomie, Seminole and Okfuskee Counties, Oklahoma. In 2007, we delivered approximately 64% of the average throughput on this system to our Paden plant and the remainder to third-party processing plants in exchange for a share of the yield of NGLs and residue gas.
 
The Paden plant has a 60,000 Mcf/d turbo-expander cryogenic facility placed in service in June 2001, and a 40,000 Mcf/d refrigeration unit that was added in May 2007. The Paden plant also has the ability to reduce the ethane extracted from natural gas processed, or “ethane rejection” capability. This capability provides us an advantage when market prices or operating conditions make it more desirable to retain ethane within the gas stream. Field compression provides the necessary pressure at the plant inlet, eliminating the need for inlet compression. The plant also has inlet condensate facilities, including vapor recovery and condensate stabilization.
 
Wellhead production around the Paden plant includes natural gas high in nitrogen, which is inert and reduces the Btu value of residue gas. Because downstream pipeline quality specifications impose limitations on nitrogen content, we are installing a nitrogen rejection unit as part of our expansion of the Paden plant, which will allow us to process increased volumes of high-nitrogen natural gas while remaining in compliance with downstream pipeline specifications. Nitrogen rejection capability, which we expect will be operational in March 2008, will allow us to remove unwanted nitrogen from residue gas at the tailgate of the plant.
 
We deliver residue gas from the Paden plant to Enogex Inc. (a subsidiary of OGE Energy Corp.) and NGLs to ONEOK Hydrocarbon.
 
Osage System
 
The Osage system is located in Osage, Pawnee, Payne, Washington and Tulsa Counties, Oklahoma. Wellhead production on the Osage system tends to be lean, and the majority of the natural gas gathered on the system is not processed. We deliver lean gas from the Osage system to Enogex, ONEOK Gas Transmission (“OGT”) and Keystone Gas. Natural gas we deliver to Keystone Gas is processed by a third-party processor and we receive a share of the NGLs and residue gas.
 
Milfay System and Processing Plant
 
The Milfay system is located in Tulsa, Creek, Payne, Lincoln and Okfuskee Counties, Oklahoma. We deliver natural gas gathered on the Milfay system to our Milfay and Paden plants. We deliver the residue gas from the Milfay plant into OGT and the NGLs to ONEOK Hydrocarbon.
 
Glenpool System and Processing Plant
 
The Glenpool system is located in Tulsa, Wagoner, Muskogee, McIntosh, Okfuskee, Okmulgee and Creek Counties, Oklahoma. Substantially all of the natural gas from the Glenpool system is delivered to our Glenpool plant. From the plant, we deliver the residue gas into either OGT or the American Electric Power Riverside power plant, and the NGLs to ONEOK Hydrocarbon.
 
Twin Rivers System
 
The Twin Rivers system is located in Okfuskee, Seminole, Hughes, Pontotoc and Coal Counties, Oklahoma. We deliver substantially all of the Twin Rivers system’s volumes to a third-party plant for processing in exchange for a share of the NGLs and residue gas. We take the residue gas in-kind at the tailgate of Enogex’s plant and sell the NGLs to Enogex.


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Mountain Systems
 
The Mountain systems are located in Atoka, Pittsburg and Latimer Counties, in the Arkoma Basin, and include the Blue Mountain, Cyclone Mountain and Pine Mountain systems. Wellhead production on the Mountain systems is lean and generally does not require processing. We deliver natural gas from the Mountain systems to, among others, CenterPoint, Enogex and Natural Gas Pipeline Company of America, or NGPL.
 
Central Oklahoma System
 
The Central Oklahoma system, which we acquired as part of Cimmarron in May 2007, has provided us with added operating presence in natural gas producing regions in central Oklahoma. The Central Oklahoma system comprises five active gathering systems located in Garvin, Stephens, McClain, Oklahoma and Carter Counties, Oklahoma. We deliver gas gathered on the Central Oklahoma system to DCP Midstream.
 
Tomahawk System
 
The Tomahawk system, which we acquired as part of Cimmarron in May 2007, is expected to be operational in March 2008. The Tomahawk system is located in Atoka, Bryan, Coal, Hughes and Seminole Counties, Oklahoma. We deliver substantially all of the natural gas gathered on the Tomahawk system to the Paden plant.
 
Crude Oil Pipeline
 
The crude oil pipeline, which we acquired as part of Cimmarron in May 2007, is located in Love, Carter and Garvin Counties, Oklahoma, and Cooke and Grayson Counties, Texas. We use the crude oil line to transport and blend sweet and sour crude oil mix for sale to crude oil marketers, including High Sierra and SemCrude.
 
Southern Dome
 
Through ScissorTail we own a majority interest in Southern Dome, LLC, or Southern Dome, which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County. We are the managing member of Southern Dome and serve as its operator. The Southern Dome plant began operating in April 2006. Southern Dome also operates a 3.4-mile gathering system owned by a single producer. Under a gas purchase and processing agreement between Southern Dome and this producer, substantially all of the natural gas from the gathering system is delivered to the Southern Dome processing plant. Southern Dome receives a fee for operating the gathering system and a percentage of the producer’s residue gas and NGLs at the tailgate of the Southern Dome plant. We deliver the residue gas to OGT and sell the NGLs to various markets via trucks.
 
We are obligated to make 73% of capital contributions requested by Southern Dome up to a maximum commitment amount of $18.25 million. We are entitled to receive 69.5% of member distributions until “payout,” which refers to a point at which we have received distributions equal to our capital contributions plus an 11% return. After payout occurs, we will be entitled to 50.1% of member distributions. As of December 31, 2007, we have made $13.5 million in aggregate capital contributions to Southern Dome and have received an aggregate of $2.0 million in member distributions.
 
Texas
 
Our Texas segment operates in southeastern and northern Texas and includes 1,853 miles of natural gas gathering and transmission pipelines, our Houston Central plant, located near Sheridan, Texas, and two NGL pipelines, one of which we lease from Kinder Morgan Texas Pipeline. Our Texas segment also includes the Lake Charles plant, located in Lake Charles, Louisiana, which we acquired as part of the Cantera acquisition. The Lake Charles plant, which has had no material operations since the acquisition, is managed by personnel who manage our Texas segment.


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The following map represents our Texas segment:
 
(TEXAS MAP)


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The tables below provide summary descriptions of our Texas pipeline systems and processing plants.
 
Texas Pipelines
 
                                         
                      Year Ended
 
                      December 31, 2007  
    Length
    Diameter of Pipe
    Throughput
    Average
    Utilization
 
    (miles)     (range)     Capacity(1)(2)     Throughput(1)(2)     of Capacity  
 
Natural Gas Pipelines:
                                       
South Texas(3)(4)
    1,102       2²- 20²       538,800       187,140       35 %
Houston Central
    313       2²- 12²       239,000       123,224       52 %
Upper Gulf Coast
    230       2²- 20²       139,000       36,728       26 %
North Texas(5)
    208       3²- 12²       28,500       18,847       66 %
NGL Pipelines:
                                       
Sheridan NGL Pipeline(6)
    104       6²       30,900       17,090       55 %
Brenham NGL Pipeline(7)
    46       6²                    
 
 
(1) Many capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacity and/or other facility upgrades.
 
(2) Natural gas pipeline throughputs are measured in Mcf/d. NGL throughputs are measured in Bbls/d.
 
(3) Includes our Webb/Duval system owned by Webb Duval, an unconsolidated partnership in which we hold a 62.5% interest.
 
(4) Throughput volumes presented in the table are net of intercompany transactions.
 
(5) Excludes 576 miles of inactive pipelines held for potential future development. Data reported for our North Texas System is only for the period from May 1, 2007 (the date of our Cimmerron acquisition) through December 31, 2007.
 
(6) We use the eastern portion of our Sheridan NGL pipeline to transport butylene and the western portion to transport NGLs from our Houston Central plant to Enterprise Products Partners’ Seminole pipeline. The central portion of our Sheridan NGL pipeline currently is inactive.
 
(7) We expect to place the Brenham NGL pipeline into service in March 2008.
 
Texas Processing
 
                                                 
                  Year Ended December 31, 2007  
                  Average
          Average Processing
 
    Associated
      Throughput
    Inlet
    Utilization
    Volumes(1)(2)  
Processing Plants
  Gathering System   Facilities   Capacity(1)     Volumes(1)     of Capacity     NGLs     Residue  
 
Houston Central
  Central Gulf Coast   Cryogenic/lean oil     700,000       522,051       75 %     16,295       483,933  
    South Texas   Ethane rejection                                        
Lake Charles(3)
    Cryogenic     200,000       11,697 (4)     6 %     260 (4)     11,439 (4)
 
 
(1) Throughput capacity and inlet volumes are measured in Mcf/d. NGL volumes are measured in Bbls/d. Residue volumes are measured in MMBtu/d.
 
(2) Production from the Houston Central plant includes average daily volumes of 14,444 Bbls/d of ethane, propane, butane and natural gasoline mix delivered to the Sheridan NGL pipeline and 1,756 Bbls/d of stabilized condensate delivered to the TEPPCO crude oil pipeline.
 
(3) The Lake Charles plant, which has had no material operations since the acquisition, is managed by personnel who manage our Texas segment.
 
(4) Average inlet volumes and average processing volumes for the Lake Charles plant represent two days of activity in October 2007.


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South Texas Systems
 
We deliver a substantial majority of the natural gas gathered on our systems in South Texas to our Houston Central plant for treating and processing, or conditioning, as needed. Our gathering systems in this area deliver to our Houston Central plant via the Laredo-to-Katy pipeline, a 30-inch diameter natural gas transmission pipeline system owned by Kinder Morgan Texas Pipeline, or KMTP, that extends along the Texas Gulf Coast from South Texas to Houston.
 
Our South Texas gathering systems that deliver natural gas to our Houston Central plant gather natural gas from fields located in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces, Refugio and San Patricio Counties. Some of these systems also deliver to NGPL, DCP Midstream, and Houston Pipe Line Co., or HPL, an affiliate of Energy Transfer Partners, Tetco and ExxonMobil.
 
Among our systems in South Texas is the Webb/Duval gathering system, which is owned by Webb Duval, a general partnership that we operate and in which we hold a 62.5% interest. We operate the Webb/Duval system subject to the rights of the other partners, including rights to approve capital expenditures in excess of $0.1 million, financing arrangements by the partnership or any expansion projects associated with this system. In addition, each partner has the right to use its pro rata share of pipeline capacity on this system, subject to applicable ratable take and common purchaser statutes.
 
Our Copano Bay gathering system and Encinal Channel pipeline, which was placed in service in April 2007, operate onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. These systems gather natural gas offshore in Aransas, Nueces and Copano Bays and from nearby onshore lands. Natural gas, produced water and condensate are separated at our Lamar and Estes Cove separation and dehydration facilities. We deliver natural gas from the Lamar facility to a third-party processing plant.
 
Houston Central Systems and Processing Plant
 
Our Houston Central gathering systems gather gas near the Houston Central plant in Colorado, DeWitt, Lavaca, Victoria and Wharton Counties, and deliver natural gas to the Houston Central plant directly, instead of via the Laredo-to-Katy pipeline. These systems can also take delivery of natural gas from Enterprise Products Partners and DCP Midstream.
 
Our Houston Central plant has approximately 700,000 Mcf/d of processing capacity and is the second largest and the most fuel efficient processing plant in South Texas. In addition to the conditioning capability described below, the Houston Central plant has:
 
  •  8,029 horsepower of inlet compression, 1,340 of which we installed in 2007;
 
  •  8,400 horsepower of tailgate compression;
 
  •  a 1,200 gallon-per-minute amine treating system for removal of carbon dioxide and low-level hydrogen sulfide;
 
  •  two 250,000 Mcf/d refrigerated lean oil trains;
 
  •  one 200,000 Mcf/d cryogenic turbo-expander train;
 
  •  a 25,000 Bbls/d NGL fractionation facility; and
 
  •  882,000 gallons of storage capacity for propane, butane-natural gasoline mix and stabilized condensate.
 
We modified the Houston Central plant to provide natural gas conditioning capability in 2003, installing two new 700 horsepower, electric-driven compressors to provide propane refrigeration through the lean oil portion of the plant, which enables us to shut down our steam-driven refrigeration compressor when conditioning natural gas. We installed a third 700-horsepower, electric-driven compressor in January 2007. These compressors allow us to process gas only to the extent required to meet pipeline hydrocarbon dew point specifications, which we refer to as conditioning. Conditioning capability allows us to preserve a greater portion of the value of natural gas when


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processing is not profitable (in other words, when natural gas prices are high relative to NGL prices) because it allows us to:
 
  •  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.
 
When we elect to condition natural gas, typically our natural gas fuel consumption volumes are reduced by approximately 80%, while our average NGLs extracted are reduced approximately 91%. At the Houston Central plant, we process or condition natural gas delivered by the KMTP Laredo-to-Katy pipeline, which the plant straddles, and the pipelines in our Sheridan and Provident City gathering systems. The plant has tailgate interconnects with KMTP, HPL, Tennessee Gas Pipeline Company and Texas Eastern Transmission for redelivery of residue natural gas. In addition, we operate our Sheridan NGL pipeline, and anticipate operating our Brenham NGL pipeline beginning in March 2008, at the tailgate of the plant. TEPPCO Partners, L.P. operates a crude oil and stabilized condensate pipeline that runs from the tailgate of the plant to refineries in the greater Houston area.
 
The Houston Central plant was first constructed in 1965 by Shell and originally consisted of single refrigerated lean oil train and a fractionation facility. Shell expanded the plant in 1985, adding a second refrigerated lean oil train, and again in 1986, adding a cryogenic turbo expander train. The plant and related facilities are located on a 163-acre tract of land, which we lease under three long-term lease agreements.
 
Sheridan and Brenham NGL Pipelines.  The western portion of the Sheridan NGL pipeline originates at the tailgate of the Houston Central plant and delivers NGLs into Enterprise Products Partners’ Seminole Pipeline on the western side of Houston. The eastern portion of the Sheridan NGL pipeline originates at the Enterprise Products Partners’ Almeda station in south Houston and delivers butylenes to the Shell Deer Park Plant on the Houston Ship Channel.
 
We expect to place the Brenham NGL pipeline, which originates at the tailgate of our Houston Central plant, into service in March 2008. We plan to use the Brenham NGL pipeline to deliver NGLs into the Enterprise Products Partners’ Seminole pipeline near Brenham, Texas. We lease the Brenham NGL pipeline from Kinder Morgan Energy Partners, L.P. under a 5-year lease agreement that commenced February 1, 2006.
 
Our Commercial Relationship With Kinder Morgan Texas Pipeline.  Kinder Morgan Texas Pipeline, or KMTP, owns a 2,500-mile natural gas pipeline system that extends along the Texas Gulf Coast from south Texas to Houston and primarily serves utility and industrial customers in the Houston, Beaumont and Port Arthur areas. KMTP sells and transports natural gas, and we use KMTP as a transporter because our Houston Central plant straddles its 30-inch-diameter KMTP Laredo-to-Katy pipeline. Using KMTP as a transporter allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central plant and downstream markets. KMTP’s pipeline also delivers to our Houston Central plant natural gas for its own account, which we refer to as “KMTP Gas.” Under our contractual arrangements relating to KMTP Gas, we receive natural gas at our plant, process or condition the natural gas and sell the NGLs to third parties at market prices. For a discussion of our agreements with KMTP, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Our Contracts.”
 
Upper Gulf Coast Systems
 
The Upper Gulf Coast systems are used for gathering, transportation and sales of natural gas to the north of Houston, Texas, in Houston, Walker, Grimes, Montgomery and Harris Counties. We also receive natural gas from interconnects with HPL, Vantex Gas Pipeline, a subsidiary of Energy Transfer Partners, KMTP, Atmos Pipeline — Texas and Texas Eastern Transmission. We deliver the natural gas gathered on these systems to multiple CenterPoint Energy city gates in Montgomery and Walker Counties, to Universal Natural Gas, a gas company that serves residential markets and Entergy’s Lewis Creek generating plant, and to several industrial consumers.


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North Texas Systems
 
As part of our May 2007 Cimmarron acquisition, we acquired natural gas gathering pipelines in North Texas, which gather natural gas from the North Barnett Shale Play in Cooke, Denton, Johnson, Montague and Wise Counties. We deliver natural gas gathered in northern Texas to third-party pipelines, and a significant portion of the gas we deliver is processed at third-party processing plants. Our systems in North Texas have interconnects with Targa Resources, Atlas Pipeline, SemGas and NGPL.
 
Rocky Mountains
 
Our Rocky Mountains segment operates in coal-bed methane producing areas in Wyoming’s Powder River Basin. We acquired the business and assets in this segment through our purchase of Denver-based Cantera in October 2007. The assets of Cantera (now Copano Natural Gas/Rocky Mountains, LLC) consist primarily of a 51.0% managing membership interest in Bighorn, a 37.04% managing membership interest in Fort Union, two firm gathering agreements with Fort Union and two firm capacity transportation agreements with Wyoming Interstate Gas Company (“WIC”). Two subsidiaries of ONEOK Partners own the remaining 49% membership interests in Bighorn and subsidiaries of Anadarko, Williams, and ONEOK Partners own the remaining 62.96% membership interests in Fort Union. Bighorn and Fort Union operate natural gas gathering systems in the Powder River Basin.
 
For the period from October 1, 2007 through December 31, 2007, total average throughput volumes for our Rocky Mountains segment were 232,169 Mcf/d. These volumes include volumes that we purchased for resale, volumes that we gathered utilizing our firm capacity gathering agreements with Fort Union and firm capacity volumes under our transportation agreements with WIC that we have released to producers in the Powder River Basin. These volumes exclude total average throughput volumes for the Bighorn and Fort Union systems, which are set forth below under “— Bighorn Gathering System” and “— Fort Union Gathering System.”


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The following map represents the assets of Bighorn and Fort Union:
 
(Map)
 
Bighorn Gathering System
 
The Bighorn gas gathering system consists of approximately 251 miles of pipeline ranging from 6” to 24” in diameter and total throughput capacity of 300,000 Mcf/d, which could be increased to 600,000 Mcf/d through additional midpoint


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compression. The Bighorn system is located in Johnson, Sheridan and Campbell Counties, Wyoming. Bighorn provides low and high pressure natural gas gathering service to coal-bed methane producers in the Powder River Basin. Due to the lean nature of coal-bed methane wellhead production, gas gathered on the Bighorn system does not require processing and is delivered directly into the Fort Union gas gathering system at the southern terminus of the Bighorn system.
 
Although we serve as manager and field operator of Bighorn, certain significant business decisions with respect to Bighorn require the majority or unanimous approval of a management committee to which we have the right to appoint 50% of the committee members. Examples of some of these substantive business decisions include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, the determination of excess cash for mandatory distribution to members, dispositions of assets or entry into new gathering agreements or amendments to existing gathering agreements, among others.
 
For the period from October 1, 2007 through December 31, 2007, total average throughput volumes for the Bighorn system were 216,584 Mcf/d.
 
Fort Union Gathering System
 
The Fort Union gas gathering system consists of two parallel 106-mile, 24” pipelines with total throughput capacity of 840,000 Mcf/d and the Medicine Bow amine treating facility with treating capacity of 300 gallons per minute, or GPM. This system, located in Campbell and Converse Counties, Wyoming, takes high pressure delivery of gas from the Bighorn system and also provides high pressure gas gathering services to producers that deliver gas directly or indirectly into the Fort Union system. Natural gas gathered from these producers is relatively high in carbon dioxide and, accordingly, must be treated at Fort Union’s Medicine Bow treating facility in order to meet the quality specifications of downstream pipelines. Pipeline interconnects downstream from the Fort Union system include WIC, Kinder Morgan Interstate Gas Transportation Company (“KMIGT”) and Colorado Interstate Gas Company (“CIG”).
 
Fort Union is in the process of expanding its system by construction of a third 106-mile, 24” loop, which is expected to be operational in the second quarter of 2008. This system expansion is expected to increase the system’s throughput capacity from 840,000 Mcf/d to 1.2 Bcf/d. Also, Fort Union has approved (subject to its members’ final approval of the business terms) the installation of two additional amine treaters at its Medicine Bow treating facility, which will expand treating capacity from 300 GPM to 1,500 GPM and which are expected to be operational in the third quarter of 2008.
 
Fort Union gathers a majority of the gas across its system under standard firm gathering agreements between Fort Union and each of its four owners, including us. Pursuant to these agreements, each of Fort Union’s owners is obligated to pay for a fixed quantity of firm gathering capacity (referred to as demand capacity) on the system, regardless of whether the owner uses the capacity. Also, each owner has the right to a portion of firm capacity on the system that is only paid for if utilized and is referred to as variable capacity. To the extent an owner does not use its allocated capacity or market it to third parties, it is available for use by the other owners. To the extent any capacity on the system is not utilized by the owners, it is available to third parties under interruptible gathering agreements. Beginning in 2009, a significant portion of the owners’ demand capacity obligations terminate and that capacity becomes available to the owners as variable capacity. The firm gathering agreements between Fort Union and its owners terminate only upon mutual agreement of the parties.
 
Although we serve as the managing member of Fort Union, we do not operate the Fort Union system, nor do we provide certain administrative services. The Anadarko subsidiary acts as field operator and conducts all construction and field operations, while the ONEOK Partners subsidiary acts as administrative manager and provides gas control, contracts management and contract invoicing services. As managing member of Fort Union, we perform all other acts incidental to the management of Fort Union’s business, including determining distributions to owners, executing gathering agreements, approving certain capital expenditures and monitoring the performance of the field operator and administrative manager, subject to the requirement that certain significant business decisions receive the 65% or unanimous approval of the owners. Examples of these significant business decisions include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, among others.


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For the period from October 1, 2007 through December 31, 2007, total average throughput volumes for the Fort Union system were 604,850 Mcf/d, including an average of 216,584 Mcf/d delivered to Fort Union by Bighorn.
 
Producer Services
 
In addition to holding managing member interests in Bighorn and Fort Union, we provide services to a number of producers in the Powder River Basin, including producers who deliver gas into the Bighorn or Fort Union gathering systems. As part of our Cantera acquisition, we acquired two firm gathering agreements with Fort Union, which currently provide us with firm demand capacity on the Fort Union system of 198,150 Mcf/d and the right to utilize up to an additional 95,952 Mcf/d of firm variable system capacity. We also acquired two transportation agreements with WIC, which provide us with approximately 226,000 MMBtu/d of firm capacity on WIC’s Medicine Bow lateral pipeline. Under these agreements, WIC transports natural gas from the terminus of the Fort Union system near Glenrock, Wyoming, as well as other receipt points, to the Cheyenne Hub, which provides a connection to five major interstate pipelines. Our WIC agreements extend through December 2019, with a right to renew for an additional five-year term. These agreements obligate us to pay for the capacity we hold on WIC’s Medicine Bow lateral whether or not we use the capacity. We use our capacity on WIC and Fort Union to provide producers access to downstream interstate markets. In April 2007, we sold, or “released,” the majority of our WIC capacity, and beginning in June 2008 all of our WIC capacity, to producers in the Powder River Basin through 2019.
 
Natural Gas Supply
 
We continually seek new supplies of natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage or by obtaining natural gas supplies that were previously transported on other third-party gathering systems. We contract for supplies of natural gas from producers under a variety of contractual arrangements. The primary term of each contract varies significantly, ranging from one month to the life of the dedicated production. The terms of our natural gas supply contracts vary depending on, among other things, gas quality, pressure of natural gas produced relative to downstream pressure requirements, competitive environment at the time the contract is executed, and customer requirements. For a summary of our most common contractual arrangements, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Our Contracts.”
 
We generally do not obtain reservoir engineering reports evaluating reserves dedicated to our pipeline systems due to the cost of such evaluations and the lack of publicly available producer reserve information. Accordingly, we do not have estimates of total reserves dedicated to our assets or the anticipated life of producing reserves.
 
Oklahoma
 
Our Oklahoma systems are located in areas that have experienced increased levels of drilling activity since 2003, which has led to increased volumes of natural gas through our Oklahoma segment’s pipeline systems. Based on our discussions with producers in this area about their production plans, we expect to continue to expand our Oklahoma systems so that we can pursue newly developed natural gas supplies.
 
The five top natural gas producers by volume in our Oklahoma segment for 2007 collectively accounted for approximately 67% of the natural gas delivered to our Oklahoma systems during that period. Pursuant to a contract that extends through mid-year 2020, our largest Oklahoma producer by volume has dedicated to us all of its production within a 1.1 million acre area. We also have dedications from other producers covering their production within an aggregate 250,000 acres pursuant to contracts ending between 2009 and 2016.
 
Texas
 
Our Texas systems are located in areas that have experienced continued significant drilling activity, providing us with opportunities to access newly-developed natural gas supplies. The five top natural gas producers by volume in our Texas segment for 2007 collectively accounted for approximately 32% of the natural gas delivered to our Texas systems during that period.


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Rocky Mountains
 
The Bighorn and Fort Union systems are located in the Powder River Basin, a major coal-bed methane exploration and development play in the United States. The Powder River Basin accounts for approximately eight out of 10 new coal-bed methane wells drilled with estimated recoverable reserves of 20 to 30 Tcf.
 
Under Fort Union’s operating agreement, the owners of Fort Union established an area of mutual interest (“AMI”) covering approximately 2.98 million acres in Converse, Campbell and Johnson Counties, Wyoming. Under the AMI, the owners have committed all gas production from the AMI to the Fort Union system up to the total capacity of the Fort Union system based on each owners total firm capacity rights.
 
The owners of Bighorn have established an approximately 3.8 million-acre area of mutual interest within the Powder River Basin of northern Wyoming and southern Montana, which provides that projects undertaken by the owners or their subsidiaries in the area of mutual interest must be conducted through Bighorn. Additionally, production from leases covering more than one million acres of land within the Powder River Basin has been dedicated to the Bighorn Gathering system by producers. Bighorn’s largest Rocky Mountains producer by volume has dedicated to Bighorn approximately 300,000 acres pursuant to a contract that extends through 2019. We also have dedications from other producers within the same Bighorn dedicated area pursuant to contracts ending between 2011 and 2019.
 
Competition
 
The midstream natural gas industry is highly competitive. Competition in the midstream natural gas industry is based primarily on the reputation, efficiency, flexibility and reliability of the gatherer, the pricing arrangements offered by the gatherer, location of the gatherer’s pipeline facilities and the gatherer’s ability to offer a full range of services, including natural gas gathering, transportation, compression, dehydration and processing.
 
We face strong competition in acquiring new natural gas supplies. Our competitors include major interstate and intrastate pipelines and other natural gas gatherers that gather, process and market natural gas. Our competitors may have capital resources and control supplies of natural gas greater than ours.
 
We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies in our operating regions.
 
Oklahoma
 
Substantially all of our Oklahoma systems offer low-pressure gathering service, which is attractive to producers. We have made significant investments in limited-emissions multi-stage compressors for our Oklahoma compression facilities, which has allowed for quicker permitting and installation, thereby allowing us to provide the pressure required by producers more efficiently. We believe this approach provides us a competitive advantage.
 
Our major competitors for natural gas supplies and markets in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, LP, Oneok Field Services, Hiland Partners, Enogex, Mark West and Enerfin Resources Company.
 
Texas
 
Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, Lobo Pipeline Company (an affiliate of ConocoPhillips), KMTP, DCP Midstream, Crosstex Energy, HPL, ExxonMobil, Targa Resources, Atlas Pipeline and Devon Energy. Competition for natural gas supplies is primarily based on the reputation, efficiency, flexibility and reliability of the gatherer, the pricing arrangements offered by the gatherer, the location of the gatherer’s pipeline facilities and the ability of the gatherer to offer a full range of services, including compression, processing, conditioning and treating services.
 
We provide comprehensive services to natural gas producers, including natural gas gathering, transportation, compression, dehydration, treating, conditioning and processing. We believe our ability to furnish these services


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gives us an advantage in competing effectively for new supplies of natural gas because we can provide the services that producers, marketers and others require to connect their natural gas quickly and efficiently.
 
In addition, using centralized treating and processing facilities, we can in most cases attach producers that require these services more quickly and at a lower initial capital cost than our competitors due in part to the elimination of some field equipment and greater economies of scale at our Houston Central plant. For natural gas that exceeds the maximum carbon dioxide and NGL specifications for interconnecting pipelines and downstream markets, we believe that we offer treating, conditioning and other processing services on competitive terms.
 
Rocky Mountains
 
Our major competitors for natural gas gathering supplies in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy and Western Gas Resources. A significant portion of the gas on the Bighorn system is dedicated to Bighorn under long-term gas gathering agreements and, accordingly, is not available to competitors. Additionally, Fort Union’s centralized amine treating facility and approved expansion provide Fort Union with a competitive advantage.
 
Industry Overview
 
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets and consists of natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation.
 
We provide natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services to our customers. These processes are illustrated in the following diagram.
 
(DIAGRAM)
 
  •  Natural gas gathering.  The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small-diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.
 
  •  Compression.  Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Because wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to


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


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  Stabilized condensate is primarily used as a refinery feedstock for the production of motor gasoline and other products.
 
NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. Fractionation takes advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off the top of the tower where it is condensed and routed to a pipeline or storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Because the fractionation process uses large quantities of heat, fuel costs are a major component of the total cost of fractionation.
 
  •  Natural gas transportation.  Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users and utilities and to other pipelines.
 
  •  NGL transportation.  NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation utilized depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, consistent volumes of NGLs are to be delivered.
 
Risk Management
 
We are exposed to market risks, including changes in commodity prices and interest rates. We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes. For a more detailed discussion of our risk management activities, please read “— Recent Developments — Hedge Activity” and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”
 
Regulation
 
FERC Regulation of Intrastate Natural Gas Pipelines.  We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission (“FERC”) does not directly regulate any of our operations. However, FERC’s regulation influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:
 
  •  the certification and construction of new facilities;
 
  •  the review and approval of cost-based transportation rates;
 
  •  the extension or abandonment of services and facilities;
 
  •  the maintenance of accounts and records;
 
  •  the acquisition and disposition of facilities; and
 
  •  the initiation and discontinuation of services.
 
Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. The Commodity Futures Trading Commission, or the CFTC, also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, NGLs and crude oil, our gathering or transportation of these energy commodities and any related hedging activities that we undertake, we are required to observe these


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anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.
 
FERC has adopted new market-monitoring and annual reporting regulations intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. Although these regulations are not administratively final, the monitoring and annual reporting mandated by these regulations could require us to incur increased costs and administrative burdens. FERC has also proposed to require both interstate and certain major non-interstate pipelines to post, on a daily basis, capacity, scheduled flow information and actual flow information. Depending upon how the regulations define “major non-interstate pipeline,” certain of our operations may also be subject to daily reporting requirements, which could subject us to further costs and administrative burdens. Our business, results of operations and financial condition could be adversely affected under these market monitoring and reporting requirements.
 
In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
 
FERC Regulation of NGL Pipelines.  We have interests in two NGL pipelines, both of which are located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to FERC jurisdiction under the ICA and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged, however. Should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs, and we may be subject to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
 
FERC Regulation of Crude Oil Pipelines.  With the acquisition of Cimmarron in May 2007, we now own a small, four-inch diameter crude oil pipeline, located in Texas and Oklahoma. Historically, this pipeline was thought to be a private carrier pipeline exempt from FERC jurisdiction. Upon further analysis, however, we believe that this pipeline provides interstate service subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”). As a result, we may be required to file and maintain published tariffs, in which case the pipeline’s rates would be required to be just and reasonable, and, when providing service, it could not confer any undue or unreasonable preference or prejudice. In any event, we expect compliance costs would be minimal.
 
Intrastate Natural Gas Pipeline Regulation.  We own intrastate natural gas transmission facilities in Texas and Oklahoma. These facilities are subject to state safety, environmental and service regulation, but are generally not subject to rate regulation by the FERC.
 
To the extent that our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act. Section 311 requires, among other things, that rates for such interstate service, which may be established by the FERC or the applicable state agency, be “fair and equitable” and permits the FERC to approve terms and conditions of service.
 
Natural Gas Gathering Regulation.  Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC. We own or hold interests in a number of natural gas pipeline systems in Texas, Oklahoma and Wyoming that we believe would meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation, so the classification and regulation of some of our gathering facilities may be subject to change based on future


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determinations by FERC and the courts. Thus, we cannot guarantee that the jurisdictional status of our natural gas gathering facilities will remain unchanged.
 
In Texas, Oklahoma and Wyoming, the states in which our gathering operations take place, we are subject to state safety, environmental and service regulation. While we are not subject to direct state regulation of our gathering rates, we are required to offer gathering services on a non-discriminatory basis. In general, the non-discrimination requirement is monitored and enforced by each state based upon filed complaints.
 
We are also subject to state ratable take and common purchaser statutes in these states. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.
 
State Utility Regulation.  Some of our operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the Texas Railroad Commission (“TRRC”). Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. None of our operations in Oklahoma have historically been, or are currently, regulated by the Oklahoma Corporation Commission (“OCC”) as public utilities. None of our operations in Wyoming have historically been, or are currently, regulated by the Wyoming Public Service Commission (“WPSC”) as public utilities.
 
Sales of Natural Gas, Crude Oil and NGLs.  The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The prices at which we sell crude oil or NGLs are not subject to federal or state regulation.
 
Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Environmental, Health and Safety Matters
 
The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing or transporting natural gas, NGLs, crude oil and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
  •  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.
 
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where wastes or other regulated substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.
 
We believe that our operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws or the development or discovery of new facts or conditions will not cause us to incur significant costs. The trend in environmental


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regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.
 
The following is a summary of the more significant current environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may require material capital expenditures or have a material adverse impact on our cash flow, results of operations or financial position:
 
Hazardous Waste.  Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many crude oil and natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of crude oil or natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.
 
Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources and for the costs of certain health studies.
 
We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas. With the acquisition of Cimmarron, we now also own or lease properties that have been used for the gathering of crude oil for a number of years. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under some properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum hydrocarbon spills or releases have occurred at some of the properties owned or leased by us. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.
 
Air Emissions.  Our operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and,


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potentially, criminal enforcement actions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.
 
Water Discharges.  Our operations are subject to the Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including petroleum hydrocarbon discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by a permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties and significant remedial obligations.
 
Pipeline Safety.  Our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”) and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases and the transportation and storage of liquefied natural gas, whereas the HLPSA covers the pipeline transportation of hazardous liquids including crude oil and petroleum products. Under both federal acts, any entity that owns or operates covered pipeline facilities is required to comply with the regulations under the NGPSA and HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable existing NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.
 
Our pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Office of Pipeline Safety, has established a series of rules which require pipeline operators to develop and implement integrity management programs for natural gas pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Similar rules are also in place for operators of hazardous liquid pipelines. The DOT is required by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 to issue new regulations that set forth safety standards and reporting requirements applicable to low stress pipelines transporting hazardous liquids, including crude oil, NGLs and condensate. In addition, the DOT published a Notice of Proposed Rulemaking (“NPRM”) in September 2006 that proposed to regulate certain onshore hazardous liquids gathering and low-stress pipeline systems found near “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species or other ecological resources. These safety standards may include applicable integrity management program requirements. While no new regulations have yet been finalized in response to the Safety Act of 2006 or the NPRM, final DOT rules are expected to be adopted during 2008. We do not expect these future regulations to have a material adverse effect on our operations. The TRRC and the OCC have adopted regulations similar to existing DOT regulations for intrastate natural gas and crude gathering and transmission lines while the Wyoming Public Service Commission has done the same only with respect to intrastate natural gas gathering and transmission lines. Compliance with existing rules has not had a material adverse effect on our operations in the past. However, we cannot assure you that this will continue in the future.
 
Employee Health and Safety.  We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”) and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.


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Anti-terrorism.  We may be subject to future anti-terrorism requirements of the United States Department of Homeland Security (“DHS”). The DHS has issued its National Infrastructure Protection Plan (“NIPP”) in an effort to “reduce vulnerability, deter threats, and minimize the consequences of attacks and other incidents.” Although the precise parameters of DHS regulations and any related sector-specific requirements are not currently known, we have initially determined that the cost of compliance with such regulations is likely to be minimal. However, there can be no guarantee that final anti-terrorism rules that might be applicable to our facilities will not impose substantial costs and administrative burdens on our operations, adversely affecting our business.
 
Other Laws and Regulations.  Recent studies have suggested that emissions of certain gases may be contributing to warming of the earth’s atmosphere. In response to these studies, many foreign nations have agreed to limit emissions of “greenhouse gases”, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, recent sessions of Congress have considered climate control legislation, with multiple bills having already been introduced in the Senate that propose to restrict greenhouse gas emissions. Several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. For instance, California adopted the “California Global Warming Solutions Act of 2006”, which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Additionally, the U.S. Supreme Court, in Massachusetts, et al. v. EPA, has required the EPA to justify its refusal to regulate carbon dioxide emissions under the Clean Air Act. Passage of climate control legislation by Congress or a revised ruling by the EPA could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Such restrictions could have many adverse effects on our business including limiting our ability to process natural gas, increasing our expenses and lowering the demand for our services.
 
Office Facilities
 
We occupy approximately 31,000 square feet of space at our executive offices in Houston, Texas under a lease expiring on May 31, 2012. At the expiration of the primary term, we have an option to renew this lease for an additional five years at then-prevailing market rates. We also occupy approximately 10,000 square feet of office space in Tulsa, Oklahoma, which serves as the executive offices for our Oklahoma employees. The Tulsa lease expires November 30, 2010 and provides us with a five-year renewal option at then-prevailing market rates. We occupy approximately 13,300 square feet of space in Englewood, Colorado, which serves as the executive offices for our Rocky Mountains employees. The Englewood lease expires September 30, 2008. We also lease property or facilities for some of our field offices. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
 
Employees
 
As of December 31, 2007, we, through our subsidiaries, CPNO Services, L.P. and ScissorTail, had 318 full-time employees and 4 part-time employees and Copano/Operations, Inc. (“Copano Operations”) employed 14 full-time employees on our behalf. None of our employees are covered by collective bargaining agreements. We consider our relations with these employees, with Copano Operations and with those Copano Operations’ employees providing services to us to be good. In exchange for providing general and administrative services to us, including employing certain personnel on our behalf, we are required to reimburse Copano Operations for its costs and expenses. To the extent these employees provide services on our behalf, we refer to them as our employees. For more information concerning our arrangement with Copano Operations, please read Note 9, “Related Party Transactions,” to the consolidated financial statements beginning on Page F-1 of this report.
 
Available Information
 
We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may


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obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including us.
 
We also make available free of charge on or through our Internet website (http://www.copanoenergy.com) or through our Investor Relations group (713-621-9547) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
 
Item 1A.   Risk Factors
 
In addition to the factors discussed elsewhere in this Annual Report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. While these are the risks and uncertainties we believe are most important, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of the following risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may impair our business operations and financial condition.
 
Risks Related to Our Business
 
We may not have sufficient cash from operations each quarter to pay our minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses.
 
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our limited liability company agreement, we must pay our operations and maintenance expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the amount of natural gas gathered and transported on our pipelines;
 
  •  the amount and NGL content of the natural gas we process;
 
  •  the price of natural gas, NGLs and crude oil;
 
  •  the relationship between natural gas and NGL prices;
 
  •  the level of our operating costs and the impact of inflation on those costs;
 
  •  the weather in our operating areas;
 
  •  the level of competition from other midstream energy companies; and
 
  •  the fees we charge and the margins we realize for our services.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
  •  the level of capital expenditures we make;
 
  •  the cost of acquisitions, if any;
 
  •  our debt service requirements;
 
  •  fluctuations in our working capital needs;
 
  •  restrictions on distributions contained in our senior secured revolving credit facility and the indenture governing our 81/8% Senior Notes due 2016 (“Senior Notes”);


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  •  our ability to make working capital borrowings under a credit facility that are eligible to be used to pay distributions;
 
  •  prevailing economic conditions; and
 
  •  the amount of cash reserves established by our Board of Directors for the proper conduct of our business.
 
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.
 
To the extent that we make acquisitions in the future and our acquisitions do not perform as expected, our future financial performance may be negatively impacted.
 
Our business strategy includes making acquisitions that we anticipate would increase the cash available for distribution to our unitholders. As a result, from time to time, we evaluate and pursue assets and businesses that we believe complement our existing operations or expand our operations into new regions where our growth strategy can be applied. In 2007, we acquired assets in north Texas and Oklahoma, through our acquisition of Cimmarron, and acquired Cantera, which expanded our operations into the Rocky Mountains region. We cannot assure you that we will be able to complete acquisitions in the future or achieve the desired results from the Cimmarron and Cantera acquisitions or any other acquisitions we complete in the future. In addition, failure to successfully assimilate our acquisitions could adversely affect our financial condition and results of operations.
 
Our acquisitions potentially involve numerous risks, including:
 
  •  operating a significantly larger combined organization and adding operations;
 
  •  difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;
 
  •  the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;
 
  •  the loss of significant producers or markets or key employees from the acquired businesses;
 
  •  the diversion of management’s attention from other business concerns;
 
  •  the failure to realize expected profitability or growth;
 
  •  the failure to realize any expected synergies and cost savings;
 
  •  coordinating geographically disparate organizations, systems and facilities; and
 
  •  coordinating or consolidating corporate and administrative functions.
 
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.
 
Our acquisitions could expose us to potential significant liabilities.
 
We generally assume the liabilities of an entity that we purchase and may assume certain liabilities relating to assets that we acquire, including unknown and contingent liabilities. We perform due diligence in connection with our acquisitions and attempt to verify the representations of the sellers, but there may be pending, threatened, contemplated or contingent claims related to environmental, title, regulatory, litigation or other matters of which we are unaware. Although we may have indemnification claims against sellers for certain of these liabilities, our right to indemnification is generally limited in amount and to claims made within a specified time period. For example,


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we have the right to indemnification from the sellers of Cimmarron and Cantera for certain liabilities, but the indemnification is also generally limited in amount and to claims made within a specified time period. Because we assume certain liabilities in connection with our acquisitions, there is a risk that we could ultimately be liable for unknown obligations of the acquired entity or relating to the acquired assets, which could materially adversely affect our operations and financial condition.
 
We may not be able to fully execute our business strategy if we encounter illiquid capital markets.
 
One component of our business strategy contemplates pursuing opportunities to acquire assets in new regions where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our growth strategy.
 
We will require substantial new capital to finance strategic acquisitions. Any limitations on our access to capital will impair our ability to execute this component of our growth strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include market conditions and offering or borrowing costs such as interest rates or underwriting discounts.
 
Our substantial indebtedness could limit our operating flexibility and impair our ability to fulfill our debt obligations.
 
We have substantial indebtedness. As of December 31, 2007 and in addition to liabilities we incurred as a result of our risk management activities, we had:
 
  •  total indebtedness of $630.0 million, including indebtedness associated with our Senior Notes and our senior secured revolving credit facility; and
 
  •  availability under our senior secured revolving credit facility of approximately $270.0 million.
 
Subject to the restrictions governing our existing indebtedness and other financial obligations, we may incur significant additional indebtedness and other financial obligations in the future. Our substantial indebtedness and other financial obligations could have important consequences to you. For example, it could:
 
  •  make it more difficult for us to satisfy our obligations with respect to our indebtedness;
 
  •  impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general company purposes or other purposes;
 
  •  result in higher interest expense in the event of increases in interest rates to the extent that any of our debt is subject to variable rates of interest;
 
  •  have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements and an event of default occurs as a result of that failure that is not cured or waived;
 
  •  require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general company requirements;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
 
  •  place us at a competitive disadvantage compared to any competitors that have proportionately less debt.
 
If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain such refinancing or equity capital or sell assets on satisfactory terms, if at all.


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Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.
 
The indenture governing our outstanding Senior Notes contains various covenants that limit our ability and the ability of specified subsidiaries to, among other things:
 
  •  sell assets;
 
  •  pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt, if any;
 
  •  make investments;
 
  •  incur or guarantee additional indebtedness or issue preferred units;
 
  •  create or incur certain liens;
 
  •  enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
 
  •  consolidate, merge or transfer all or substantially all of our assets;
 
  •  engage in transactions with affiliates;
 
  •  create unrestricted subsidiaries; and
 
  •  enter into sale and leaseback transactions.
 
Our senior secured revolving credit facility contains similar covenants as well as covenants that require us to maintain specified financial ratios and satisfy other financial conditions. The restrictive covenants in our indenture and in the senior secured revolving credit facility could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. We may be unable to comply with these covenants. Any future breach of any of these covenants could result in a default under the terms of the indenture or our senior secured revolving credit facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against any collateral.
 
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.
 
Our gathering and transmission pipeline systems are connected to natural gas fields and wells, for which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our pipeline systems and our processing plants, we must continually obtain new natural gas supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas and attract new customers to our gathering and transmission lines include: (i) the level of successful drilling activity near our gathering systems and (ii) our ability to compete for the attachment of such additional volumes to our systems.
 
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations, the amount of reserves underlying the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, rig availability, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.
 
We face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency,


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flexibility and reliability. Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, Lobo Pipeline Company, KMTP, DCP Midstream, Crosstex Energy, ExxonMobil, HPL, Targa Resources, Atlas Pipeline and Devon Energy. The primary competitors in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, ONEOK Field Services, Enogex, Enerfin, Hiland Partners and MarkWest. The primary competitors in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy and Western Gas Resources. A number of our competitors are larger organizations than we are.
 
If we are unable to maintain or increase the throughput on our pipeline systems because of decreased drilling activity in the areas in which we operate, decreased production from the wells connected to our systems or an inability to connect new supplies of gas and attract new customers to our gathering and transmission lines, then our business and financial results or our ability to achieve our growth strategy could be materially adversely affected. Please read Item 1, “Business — Natural Gas Supply” in this Annual Report for more information on our access to natural gas supplies.
 
We rely on KMTP’s Laredo-to-Katy pipeline to transport natural gas to our Houston Central processing plant, and an NGL pipeline owned by ONEOK Hydrocarbon to transport NGLs from our Paden processing plant. If one of these pipelines were to become unavailable, our cash flows, results of operations and financial condition could be adversely affected.
 
Our ability to contract for natural gas supplies in the Texas region will often depend on our ability to deliver gas to our Houston Central plant and downstream markets, and we rely on KMTP’s Laredo-to-Katy pipeline to transport natural gas from our South Texas systems to the Houston Central plant. For the year ended December 31, 2007, approximately 42% of the total natural gas delivered by our Texas segment was delivered to KMTP, and approximately 76% of the natural gas volumes processed or conditioned at our Houston Central plant were delivered to the plant through the KMTP Laredo-to-Katy pipeline.
 
If KMTP’s pipeline were to become unavailable for any reason, the volumes transported to our Houston Central plant would be reduced substantially, and our revenues and operating income from our Texas processing business could be adversely affected. In addition, much of the natural gas we gather in South Texas contains NGLs that must be removed in order to meet downstream market quality specifications. If we were unable to ship such natural gas to our Houston Central plant for processing or conditioning, and, if required, treating, we would need to arrange for an alternate means of removing NGLs and transport through other pipelines. Alternatively, we might be required to lease smaller treating and processing facilities so that we could treat and condition or process natural gas as needed to meet pipeline quality specifications.
 
In addition, we rely on ONEOK Hydrocarbon to take delivery of NGLs from our Paden and Milfay plants in Oklahoma. If ONEOK Hydrocarbon’s NGL pipeline were to be come unavailable, we would be required to run one or both of these plants in a reduced operating mode and make arrangements to re-route a portion of the natural gas we receive for processing to third-party plants, as well as make arrangements to transport NGLs to market by truck. A prolonged interruption or reduction of service on ONEOK Hydrocarbon’s NGL pipeline could hinder our ability to contract for natural gas supplies, which in turn would adversely affect our revenues and operating income.
 
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.
 
We generally do not obtain reservoir engineering reports evaluating natural gas reserves connected to our pipeline systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our pipeline systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas transported on our pipelines in the future could be less than we anticipate. A decline in the volumes of natural gas transported on our pipeline systems may cause our revenues to be less than we expect which could have a material adverse effect on our business, financial condition and our ability to make cash distributions to you.


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We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse impact on our cash flows, results of operations and financial condition.
 
Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could have an adverse impact on our operating results and could adversely impact our liquidity.
 
Our profitability depends upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.
 
Our profitability is affected by prevailing NGL and natural gas prices, and we are subject to significant risks due to fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2007, the Houston Ship Channel, or HSC, natural gas index price ranged from a high of $7.51 per MMBtu to a low of $5.23 per MMBtu. A composite of the Oil Price Information Service, or OPIS, Mt. Belvieu monthly average NGL price based upon our average NGL composition during the year ended December 31, 2007 ranged from a high of approximately $1.462 per gallon to a low of approximately $0.834 per gallon.
 
In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a 1-cent per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $1.3 million to our total segment gross margin for the year ended December 31, 2007. We also calculated that a 10-cent per MMBtu increase in the price of natural gas would have resulted in approximately a $1.2 million decrease to our total segment gross margin, and vice versa, for the year ended December 31, 2007. These relationships are not necessarily linear. Although our sensitivity analysis takes into account our hedge portfolio, it does not fully reflect the effects of our hedging program due to the prices received for natural gas and NGLs during the year ended December 31, 2007. If actual prices were to fall below the strike prices of our hedges, sensitivity to the change in commodity prices would be reduced. Additionally, if processing margins were negative, we could operate our Houston Central plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact to our total segment gross margin. For a discussion of total segment gross margin, a non-GAAP financial measure, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Overview.” For a discussion of our risk management activities and our ability to condition gas at our Houston Central plant, please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” and Item 1, “Business — Our Segments — Texas Houston Central Systems and Our Houston Central Processing Plant,” respectively.
 
The markets and prices for natural gas and NGLs depend upon many factors beyond our control. These factors include demand for oil, natural gas, liquefied natural gas, or LNG, nuclear energy, coal and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
 
  •  the impact of weather on the demand for oil and natural gas;
 
  •  the level of domestic oil and natural gas production;
 
  •  the availability of imported oil, natural gas, liquefied natural gas and NGLs;
 
  •  international demand for LNG, oil and NGLs;
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the availability of local, intrastate and interstate transportation systems;
 
  •  the availability and marketing of competitive fuels;
 
  •  the impact of energy conservation efforts; and
 
  •  the extent of governmental regulation and taxation.


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Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.
 
Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. Specifically, we have executed (i) put options and call spread options with respect to natural gas, (ii) put options and swaps with respect to certain NGL products and (iii) put options with respect to crude oil. We also have exposure to interest rate fluctuations as a result of variable rate revolving debt under our credit agreement. We have entered into interest rate swap agreements to convert a portion of this variable rate debt to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. Please read Item 7A “Quantitative and Qualitative Disclosures about Market Risk” for a summary of our commodity and interest rate hedges at December 31, 2007.
 
We have entered into derivative transactions related to only a portion of our variable rate debt and of the volume of our expected natural gas and condensate supply, production of NGLs and natural gas requirements. As a result, we will continue to have direct interest rate and commodity price risk with respect to the unhedged portion. To the extent we hedge our commodity price and interest rate risk using swap instruments, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.
 
Even though our hedging activities are monitored by management, these activities could reduce our cash flow in some circumstances, including if the counterparty to the hedging contract defaults on its contract obligations, if there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received or if production is less than expected. If the actual amount of production is lower than the amount that is subject to our swap instruments, we might be forced to satisfy all or a portion of our swap transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our cash flow.
 
The accounting standards regarding hedge accounting are rigorous. Our earnings could be subject to increased volatility to the extent our derivatives do not continue to qualify for hedge accounting. Also, to the extent we are unable to obtain, or choose not to seek hedge accounting in conjunction with any future acquisitions as a result of the type of commodity risk assumed, or structure of such acquisition, our earnings could be subject to increased volatility. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
 
We will continue to evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangement or that our future hedging arrangements will be on terms similar to our existing hedging arrangements.
 
Federal, state or local regulatory measures could adversely affect our business.
 
Our pipeline transportation and gathering systems are subject to federal, state and/or local regulation. Most of our natural gas pipeline assets are gathering systems that are considered non-utilities in the states in which they are located. The Natural Gas Act, or NGA, leaves any economic regulation of natural gas gathering to the states. Texas, Oklahoma and Wyoming, the states in which our pipeline facilities are located, do not currently regulate gathering fees.
 
Our gathering fees and our terms and conditions of service may nonetheless be constrained through state anti-discrimination laws. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities. Natural gas producers, shippers and other affected parties may file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with regard to rates and terms of service. A successful complaint, or new laws or regulatory rulings related to gathering, could increase our costs or require us to alter our gathering charges, and our business, and therefore, results of operations and financial condition could be adversely affected. Other state laws and regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for gathering, purchase, processing and sale, including state regulation of production rates and maximum daily production allowables from gas wells.


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Some of our intrastate natural gas transmission pipelines are subject to regulation as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction over these pipelines extends to both rates and pipeline safety. The rates we charge for transportation services in Texas are deemed just and reasonable under Texas law unless challenged in a complaint. A successful complaint, or new state laws or regulatory rulings related to intrastate transmission, could increase our costs or require us to alter our service charges, and our business, results of operations and financial condition could be adversely affected.
 
To the extent that our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to regulation by the FERC pursuant to Section 311 of the Natural Gas Policy Act of 1978, or NGPA. Section 311 requires, among other things, that rates for such interstate service, which may be established by the FERC or the applicable state agency, be “fair and equitable” and permits the FERC to approve terms and conditions of service. If our Section 311 rates are successfully challenged, if we are unable to include all of our costs in the cost of service approved in a future rate case, if FERC changes its regulations or policies, or establishes more onerous terms and conditions applicable to Section 311 service, this may adversely affect our business. Any reduction in our rates could have an adverse effect on our business, results of operations and financial condition. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
 
The price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC. The FERC and CFTC hold substantial enforcement authority under the anti-market manipulation laws and regulations, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.
 
The FERC has also promulgated additional market-monitoring and reporting regulations intended to increase the transparency of wholesale energy markets, protect the integrity of such markets, and improve the FERC’s ability to assess market forces and detect market manipulation.
 
These and other new laws and regulations or any administrative or judicial re-interpretations of existing laws, regulations or agreements could require us to incur increased costs and administrative burdens, and our business, results of operations and financial condition could be adversely affected. For instance, on February 19, 2008, the U.S. Supreme Court agreed to hear arguments in a lawsuit, Montana v. Wyoming, filed by the State of Montana against Wyoming over water rights in two rivers that flow through both states. Montana is asserting that Wyoming is using too much water from the Tongue and Powder Rivers pursuant to the Yellowstone River Compact, an agreement that both states entered into in 1950 addressing how the states may share water from the Yellowstone River and its tributaries, including the Tongue and Powder Rivers. A critical element of Montana’s argument is that the Compact applies to groundwater and, among other things, that Wyoming’s permitting of coal bed methane production, which involves the pumping of large quantities of groundwater, is depleting the waters of the two rivers to the detriment of Montana and its water users and in violation of the Compact. Wyoming’s position is that the Compact does not address groundwater. Among other things, Montana asks the High Court to declare the rights of Montana to water from these two rivers pursuant to the Compact and to issue a decree commanding Wyoming in the future to deliver the waters of these two rivers to Montana in accord with the Compact. This lawsuit has only recently been accepted for review by the U.S. Supreme Court and no substantive determination has yet been made regarding the use of waters from these two rivers, including the associated groundwater. Any decision made by the U.S. Supreme Court as a result of this case that effectively limits the amount of groundwater pumped in connection with coal bed methane production in Wyoming may have significant adverse impacts on the volume of production by coal bed methane producers in affected areas of Wyoming and, correspondingly, on gathering services that Bighorn and Fort Union provide.
 
For additional information on the federal, state and local regulations affecting our business, please read the subsections under Item 1 captioned “Business — Regulation” and “— Environmental Matters.”


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A change in the characterization of some of our assets by federal, state or local regulatory agencies could adversely affect our business.
 
Section 1(b) of the NGA provides that the FERC’s jurisdiction does not extend to facilities used for the production or gathering of natural gas. “Gathering” is not specifically defined by the NGA or its implementing regulations, and there is no bright-line test for determining the jurisdictional status of pipeline facilities. Although some guidance is provided by case law, the process of determining whether facilities constitute gathering facilities for purposes of regulation under the NGA is fact-specific and subject to regulatory change. Additionally, our construction, expansion, extension or alteration of pipeline facilities may involve regulatory, environmental, political and legal uncertainties, including the possibility that physical changes to our pipeline systems may be deemed to affect their jurisdictional status.
 
The distinction between FERC-regulated natural gas transmission services and federally unregulated gathering services has been the subject of regular litigation, as has been the line between intrastate and interstate transportation services. Thus, the classification and regulation of some of our natural gas gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by the FERC and/or the courts. Should any of our natural gas gathering or intrastate facilities be deemed to be jurisdictional under the NGA, we could be required to comply with numerous federal requirements for interstate service, including laws and regulations governing the rates charged for interstate transportation services, the terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the initiation and discontinuation of services, the monitoring and posting of real-time system information and many other requirements. Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders could result in substantial penalties and fines. It is also possible that our gathering facilities could be deemed by a relevant state commission or court, or by a change in law or regulation, to constitute intrastate pipeline subject to general state law and regulation of rates and terms and conditions of service. A change in jurisdictional status through litigation or legislation could require significant changes to the rates, terms and conditions of service on the affected pipeline, could increase the expense of providing service and adversely affect our business.
 
The distinction between FERC-regulated common carriage of crude oil and NGLs, and the non-jurisdictional intrastate transportation of those energy commodities, has also been the subject of litigation. The FERC, under the ICA, the Energy Policy Act of 1992, and rules and orders promulgated thereunder, regulates the tariff rates for interstate crude oil and NGL transportation and these rates must be filed with the FERC. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. To the extent any of our NGL or crude oil assets are subject to the jurisdiction of FERC, the FERC’s rate-making methodologies could limit our ability to set rates that we might otherwise be able to charge, could delay the use of rates that reflect increased costs, and could subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow. For additional information concerning FERC and other regulatory agencies relating to our business, please read “Business — Regulation.”
 
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
 
We are subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States oil and natural gas transportation pipelines and gathering lines meeting certain operational risk and location requirements. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
 
Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with non-exempt pipeline. Such costs and liabilities might relate to repair, remediation, preventative or


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mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, we may be affected by the testing, maintenance and repair of pipeline facilities downstream from our own facilities. Our NGL pipelines are also subject to integrity management and other safety regulations imposed by the TRRC.
 
Any regulatory expansion of the existing pipeline safety requirements or the adoption of new pipeline safety requirements could also increase our cost of operation and impair our ability to provide service during the period in which assessments and repairs take place, adversely affecting our business.
 
Because we handle natural gas, crude oil and other petroleum products in our pipeline and processing businesses, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
 
The operation of our gathering systems, plants and other facilities is subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose of wastes and other regulated substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.
 
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas, crude oil and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance. Please read “Business — Environmental Matters.”
 
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.
 
One of the ways we may grow our business is through the construction of additions to our existing gathering and transportation systems (including additional compression) and modifications to, or construction of, natural gas processing plants. The construction of additions or modifications to our existing gathering and transportation systems and processing and treating facilities, and the construction of new gathering and processing facilities, involve numerous regulatory, environmental, political, legal and operational uncertainties beyond our control and require the expenditure of significant amounts of capital. These projects also involve numerous economic uncertainties including the impact of inflation on project costs and the availability of required resources. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, we may not receive any material increase in operating cash flow from a project for some time. If we experience unanticipated or extended delays in generating operating cash flow from these projects, then we may need to reduce or reprioritize our capital budget in order to meet our capital requirements. We may also rely on estimates of future production in our decision to construct additions to our gathering and transportation systems, which may


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prove to be inaccurate because of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return and that, in turn, could adversely affect our cash flows and results of operations.
 
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.
 
The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing rights-of-way increases, then our results of operations could be adversely affected. In addition, increased rights-of-way costs could impair our ability to grow.
 
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.
 
Our operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:
 
  •  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.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. In addition, mechanical malfunctions, undetected ruptures in pipelines, faulty measurement or other errors may result in significant costs or lost revenues. Our operations are primarily concentrated in the Texas Gulf Coast and north Texas regions, in central and eastern Oklahoma and in Wyoming, and a natural disaster or other hazard affecting any of these areas could have a material adverse effect on our operations. For example, although we did not suffer significant damage, Hurricane Katrina and Hurricane Rita damaged gathering systems, processing facilities and NGL fractionators along the Gulf Coast in August and September 2005, respectively, which curtailed or suspended the operations of various energy companies with assets in the region. There can be no assurance that insurance will cover all damages and losses resulting from these types of natural disasters. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we generally do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. Our business interruption insurance covers only certain lost revenues arising from physical damage to our processing plants and certain pipeline facilities. 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.
 
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.
 
Substantially all of our revenues are generated from our gathering, dehydration, treating, conditioning, processing and transportation businesses, and as a result, our financial condition depends upon prices of, and


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continued demand for, natural gas and NGLs. Furthermore, substantially all of our assets are located in Texas, Oklahoma and Wyoming. Due to our limited diversification in asset type and location, an adverse development in one of these businesses or in these areas would have a significantly greater impact on our cash flows, results of operations and financial condition than if we maintained more diverse assets.
 
If we fail to maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results or prevent fraud. As a result, we may experience materially higher compliance costs.
 
In early 2005, we began a process to annually document and evaluate our internal control over financial reporting in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related regulations, which require annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent registered public accounting firm addressing these assessments. In this regard, management has dedicated internal resources, engaged outside consultants and adopted a detailed work plan to (i) assess and document the adequacy of our internal control over financial reporting, (ii) take steps to improve control processes, where appropriate, (iii) validate through testing that controls are functioning as documented and (iv) implement a continuous review and reporting process for internal control over financial reporting. Our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and the related regulations regarding our assessment of our internal control over financial reporting and our independent registered public accounting firm’s audit of that assessment have resulted, and are likely to continue to result, in increased expenses. We cannot be certain that these measures will ensure that we maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. If compliance with policies or procedures deteriorate and we fail to correct any associated issues in the design or operating effectiveness of our internal control over financial reporting or fail to prevent fraud, current and potential holders of our securities could lose confidence in our financial reporting, which could harm our business.
 
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.
 
In addition to our wholly owned subsidiaries, we own interests in a number of entities in which third parties also own an interest. These interests include our:
 
  •  62.5% interest in Webb/Duval Gatherers;
 
  •  majority interest in Southern Dome, LLC;
 
  •  51% interest in Bighorn Gas Gathering, L.L.C.; and
 
  •  37.04% interest in Fort Union Gas Gathering, L.L.C.
 
Although we serve as operator of Webb/Duval Gatherers, managing member and operator of Southern Dome, managing member and field operator of Bighorn and managing member of Fort Union, certain substantive business decisions with respect to these entities require the majority or unanimous approval of the owners or, in the case of Bighorn, of a management committee to which we have the right to appoint 50% of the members. Examples of some of these substantive business decisions include significant expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital and transactions not in the ordinary course of business, among others. Differences in views among the respective owners of these entities could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting their respective businesses and results of operations or prospects and, in turn, the amounts and timing of cash from operations distributed to their respective members or partners, including us.
 
In addition, we do not control the day-to-day operations of Fort Union. Our lack of control over Fort Union’s day-to-day operations and the associated costs of operations could result in our receiving lower cash distributions than we anticipate, which could reduce our cash flow available for distribution to our unitholders.


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Risks Related to Our Structure
 
Our limited liability company agreement prohibits a unitholder who acquires 15% or more of our common units without the approval of our Board of Directors from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.
 
Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Laws, or the DGCL. Section 203 of the DGCL as it applies to us prevents an interested unitholder, defined as a person who owns 15% or more of our outstanding units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our Board of Directors, including discouraging takeover attempts that might result in a premium over the market price for our common units.
 
Our cap on certain general and administrative expenses expired on December 31, 2007, and our pre-IPO investors are no longer required to reimburse us for certain amounts in excess of the cap, which could materially reduce the cash available for distribution to our unitholders.
 
Pursuant to our limited liability company agreement, our pre-IPO investors agreed to reimburse us for the general and administrative expenses we incurred for the years 2005 through 2007 in excess of levels set forth in our limited liability company agreement (subject to certain limitations). In satisfaction of this obligation, our pre-IPO investors made capital contributions to us of $4.1 million, $4.6 million, $10.0 million and $3.9 million in 2005, 2006, 2007 and 2008, respectively. Commencing with the first quarter of 2008, our pre-IPO investors no longer have this reimbursement obligation. As a result, all of our general and administrative expenses will be paid by us, which could materially reduce the cash available for distributions to our unitholders.
 
We may issue additional common units without your approval, which would dilute your existing ownership interests.
 
We may issue an unlimited number of limited liability company interests of any type, including common units, without the approval of our unitholders. Our limited liability company agreement does not give the unitholders the right to approve our issuance at any time of equity securities ranking junior to the common units.
 
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  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.
 
If, at any time, any person owns more than 90% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your units.


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Certain of our investors may sell units in the public market, which could reduce the market price of our outstanding common units.
 
Pursuant to agreements with our pre-IPO investors and investors in private placements effected in 2005, 2006 and 2007, we have filed or agreed to file registration statements on Form S-3 registering sales by selling unitholders of an aggregate of 39,354,334 of our common units (as adjusted to reflect the March 30, 2007 two-for-one split of all of our outstanding common units), including:
 
  •  1,184,557 common units to be issued upon conversion of Class C units we issued to the sellers in the Cimmarron acquisition;
 
  •  3,245,817 common units to be issued upon conversion of Class D units we issued to the sellers in the Cantera acquisition; and
 
  •  5,598,836 common units to be issued upon conversion of Class E units issued in our October 19, 2007 private placement.
 
While investors have routinely sold common units registered under our effective registration statements, a significant number of common units remains unsold pursuant to these registration statements. If investors holding these units were to dispose of a substantial portion of these units in the public market, whether in a single transaction or series of transactions, it could temporarily reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.
 
Tax Risks to Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for tax purposes or we were to become subject to a material amount of entity-level taxation, it would substantially reduce the amount of cash available for distribution to our unitholders.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
Despite the fact that we are a limited liability company under Delaware law, it is possible in certain circumstances for a limited liability company such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we should be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss or deduction would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of our common units.
 
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we were subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending December 31, 2007. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our federal gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to our unitholders. Moreover, at the federal level, legislation has been


39


 

proposed that would eliminate pass-through tax treatment for certain publicly traded limited liability companies. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Additionally, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
 
Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount will be adjusted to reflect the impact of that law on us.
 
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.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may disagree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
 
A unitholder will be required to pay taxes on the share of our income allocated to you even if you do not receive any cash distributions from us.
 
Because our unitholders are treated as partners to whom we allocate taxable income, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, regardless of the amount of any distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
 
Tax gain or loss on disposition of our common units could be more or less than expected.
 
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell, will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
 
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.


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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.
 
Because we cannot match transferors and transferees of common units and for certain other reasons, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
 
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.
 
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. While we would continue our existence as a Delaware limited liability company, our technical termination would, among other things result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
 
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.
 
In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently do business and own assets in Texas, Oklahoma, Wyoming and Louisiana. Although Texas and Wyoming do not currently impose a personal income tax, Oklahoma and Louisiana do and as we make acquisitions or expand our business, we may do business or own assets in other jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
A description of our properties is contained in Item 1 “Business” of this Annual Report. Substantially all of our pipelines are constructed under rights-of-way granted by the apparent record landowners. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.


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Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.
 
We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties nor will they materially interfere with their use in the operation of our business.
 
Item 3.   Legal Proceedings
 
Although we may, from time-to-time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not currently a party to any material legal proceedings, except for proceedings described below, which we have determined not to be material to us because we are fully indemnified. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.
 
As a result of our acquisition of Cantera in October 2007, we became a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMS Field Services, Inc. (“CMSFS”) and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred prior to the acquisition of CMSFS by Cantera Resources, Inc. in June 2003 (the “CMS Acquisition”). Pursuant to the acquisition agreement executed in connection with the CMS Acquisition, CMS Gas Transmission Company (“CMS”) has assumed responsibility for the defense of these claims, and we are fully indemnified by CMS against any losses that we may suffer as a result of these claims.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
None.


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PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
 
Our common units representing limited liability company interests in us are listed on The NASDAQ Stock Market LLC, or NASDAQ, under the symbol “CPNO.” On February 15, 2008, the closing market price for our common units was $35.10 per unit, and there were approximately 72 common unitholders of record. Effective February 14, 2007, our 3,519,126 subordinated units (7,038,252 on a post-split basis) converted to common units on a one-for-one basis as a result of the satisfaction of the financial tests required for conversion of the subordinated units into common units, as set forth in our limited liability company agreement. Prior to conversion of the subordinated units, there was no established public trading market for our subordinated units.
 
There is no established public trading market for our Class C units, our Class D units or our Class E units. On February 15, 2008, there were approximately 18 Class C unitholders of record, one Class D unitholder of record and 19 Class E unitholders of record.
 
On February 15, 2007, our Board of Directors approved a two-for-one unit split of our outstanding units, which entitled each unitholder of record at the close of business on March 15, 2007, to receive one additional common unit for every common unit held on that date.
 
The following table shows the high and low sales prices per common unit, as reported by NASDAQ, for the periods indicated (as adjusted to reflect the two-for-one split of all of our common units outstanding on March 15, 2007):
 
                         
    Price of
    Cash
 
    Common Units     Distribution
 
    High     Low     per Common Unit  
 
2007:
                       
Quarter Ended December 31
  $ 39.75     $ 33.53     $ 0.5100  
Quarter Ended September 30(1)
  $ 44.81     $ 33.25     $ 0.4700  
Quarter Ended June 30
  $ 45.03     $ 33.92     $ 0.4400  
Quarter Ended March 31
  $ 35.10     $ 28.85     $ 0.4200  
2006:
                       
Quarter Ended December 31
  $ 31.67     $ 26.38     $ 0.4000  
Quarter Ended September 30
  $ 27.40     $ 23.37     $ 0.3750  
Quarter Ended June 30
  $ 24.88     $ 21.64     $ 0.3375  
Quarter Ended March 31
  $ 22.48     $ 19.05     $ 0.3000  
 
 
(1) Pursuant to the agreement among us and the accredited investors in our October 2007 private placement, common units we issued in the private placement were not eligible to receive distributions for the quarter ended September 30, 2007.
 
Within 45 days after the end of each quarter, we intend to pay quarterly distributions (in February, May, August and November of each year) to the extent we have sufficient available cash from operating surplus, as defined in our limited liability company agreement, no less than the minimum quarterly distribution, or MQD of $0.20 per unit ($0.80 on an annual basis), to our common unitholders of record on the applicable record date.
 
In the event we do not have sufficient cash to pay our distributions as well as satisfy our other operational and financial obligations, our Board of Directors has the ability to reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments.
 
Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less retained cash reserves that our Board of Directors determines are necessary to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments, or other agreements; or (iii) provide funds for distributions to our unitholders for any one or more of the next four quarters; plus all cash on hand for the quarter


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resulting from eligible working capital borrowings made after the end of the quarter on the date of determination of available cash. Operating surplus generally consists of cash on hand at the closing of our IPO, cash generated from operations after deducting related expenditures and other items, plus eligible working capital borrowings after the end of the quarter, plus $12.0 million, as adjusted for reserves. Our current credit facility does not provide for working capital borrowings that would be eligible for inclusion in available cash or operating surplus.
 
Our Board of Directors has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations.
 
Distributions
 
Common Units
 
The following table sets forth information regarding distributions to our common unitholders (in thousands except for per unit numbers):
 
                             
    Distribution
                   
Quarter Ending(a)
  Per Unit     Date Declared   Record Date   Payment Date   Amount  
 
March 31, 2006
  $ 0.3000     April 18, 2006   May 1, 2006   May 15, 2006   $ 11,000  
June 30, 2006
  $ 0.3375     July 19, 2006   August 1, 2006   August 14, 2006   $ 12,400  
September 30, 2006
  $ 0.3750     October 18, 2006   November 1, 2006   November 14, 2006   $ 13,800  
December 31, 2006
  $ 0.4000     January 18, 2007   February 1, 2007   February 14, 2007   $ 17,025  
March 31, 2007
  $ 0.4200     April 18, 2007   May 1, 2007   May 15, 2007   $ 17,881  
June 30, 2007
  $ 0.4400     July 18, 2007   August 1, 2007   August 14, 2007   $ 18,743  
September 30, 2007(b)
  $ 0.4700     October 17, 2007   November 1, 2007   November 14, 2007   $ 20,276  
December 31, 2007
  $ 0.5100     January 16, 2008   February 1, 2008   February 14, 2008   $ 24,336  
 
 
(a) Before February 14, 2007, the date on which our 3,519,126 subordinated units (7,038,252 on a post-split basis) converted into common units, we paid cash distributions on all common and subordinated units then outstanding.
 
(b) Pursuant to the agreement among us and the accredited investors in our October 2007 private placement, common units we issued in the private placement were not eligible to receive distributions for the quarter ended September 30, 2007.
 
The amount of available cash from operating surplus needed to pay the current distribution of $0.51 per unit, or $2.04 per unit annualized, to our common unitholders is as follows (in thousands):
 
                 
    One Quarter     Four Quarters  
 
Common units(1)
  $ 24,336     $ 97,342  
                 
 
 
(1) Includes restricted common units and phantom units issued under our Long-Term Incentive Plan, or LTIP. Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of February 1, 2008, we had 241,181 outstanding restricted units and 106,545 outstanding phantom units. Annual distributions related to these restricted units and phantom units are approximately $0.7 million.


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In February 2007, our Board of Directors confirmed that the financial tests required for conversion of all our outstanding subordinated units into common units had been satisfied. Accordingly, our 3,519,126 subordinated units (7,038,252 on a post-split basis) converted on a one-for-one basis into common units effective February 14, 2007, the payment date for our fourth quarter 2006 distribution to unitholders. The conversion of the subordinated units did not impact the amount of cash distributions paid by us or the total number of our outstanding units.
 
Class C Units
 
Our limited liability agreement provides that up to 25% of the total Class C units we issued in connection with the Cimmarron acquisition (less any Class C units released to us in satisfaction of certain indemnity obligations of the Cimmarron sellers) will convert into common units on each of May 1 and November 1, 2008 and May 1, 2009. Class C units are not entitled to receive quarterly cash distributions. On November 1, 2007, 394,852 of the Class C units, or 25% of the total Class C units issued, converted to common units.
 
Class D Units
 
Our Class D units, which we issued to the Cantera sellers as part of the consideration for the Cantera acquisition, are convertible into our common units on a one-for-one basis upon the earlier of (a) payment of our common unit distribution with respect to the fourth quarter of 2009 or (b) our payment of $6.00 in cumulative distributions per common unit (beginning with our distribution with respect to the fourth quarter of 2007) to common unitholders. The Class D units are not entitled to receive cash distributions. No vote of our common unitholders will be required to convert the Class D units to common units.
 
Class E Units
 
Our Class E units, which we issued to accredited investors as part of our equity financing of the Cantera acquisition, have no distribution rights until our distribution with respect to the fourth quarter of 2008, when the Class E units then outstanding, if any, will become entitled to a special quarterly distribution equal to 110% of the quarterly common unit distribution. The Class E units will convert into common units upon payment of our distribution to common unitholders with respect to the third quarter of 2008, if the conversion terms of the Class E units are approved by our existing common unitholders and our Class C unitholders. Our Board of Directors has convened a special meeting of our unitholders for March 13, 2008 to consider this proposal.
 
Unitholder Return Performance Presentation
 
The performance graph below compares the cumulative total unitholder return on our common units, based on the market price of our common units, with the cumulative total return of the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies calculated by Standard & Poor’s using a float-adjusted market capitalization methodology. The Alerian Total Return Index is disseminated by the New York Stock Exchange real-time on a price return basis (NYSE: AMZX). Cumulative total return is based on annual total return, which assumes reinvested dividends or distributions for the period shown in the performance graph and assumes that $100 was invested in our company at the last reported sale price of our common units as reported on the NASDAQ ($11.35) (as adjusted for the common unit split) on November 9, 2004 (the day trading of our common units commenced) and in the S&P 500 Index and the Alerian Total Return Index on the same date. The results shown in the graph below are not necessarily indicative of future performance.
 


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(GRAPH)
 
                                         
    November 9,
    December 31,  
    2004     2004     2005     2006     2007  
 
Copano (CPNO)
  $ 100     $ 126 (a)   $ 180 (b)   $ 288 (c)   $ 367 (d)
Alerian MLP Total Return Index (AMZX)
  $ 100     $ 106     $ 113     $ 142     $ 160  
S&P 500 (SPX)
  $ 100     $ 104     $ 107     $ 122     $ 126  
 
 
(a) Based on the last sale price of our common units reported on the NASDAQ on December 31, 2004, as adjusted for the common unit split ($14.25).
 
(b) Based on the last sale price of our common units reported on the NASDAQ on December 30, 2005, as adjusted for the common unit split ($19.525).
 
(c) Based on the last sale price of our common units reported on the NASDAQ on December 29, 2006, as adjusted for the common unit split ($29.80).
 
(d) Based on the last sale price of our common units reported on the NASDAQ on December 31, 2007 ($36.35).
 
Notwithstanding anything to the contrary set forth in any of our previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 that might incorporate this Annual Report or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.
 
Securities Authorized for Issuance Under Equity Compensation Plans
 
Please read the information incorporated by reference under Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” of this Annual Report regarding securities authorized for issuance under our equity compensation plans, which information is incorporated by reference into this Item 5.

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Issuer Purchases of Equity Securities
 
None.
 
Recent Sales of Unregistered Securities
 
None.
 
Item 6.   Selected Financial Data
 
Selected Historical Consolidated Financial and Operating Data
 
The following table shows selected historical consolidated financial and operating data of Copano Energy, L.L.C. for the periods and as of the dates indicated. The selected historical consolidated financial data for the years ended December 31, 2007, 2006, 2005, 2004 and 2003 are derived from the audited consolidated financial statements of Copano Energy, L.L.C.
 
The following table includes the following non-GAAP financial measures: (1) EBITDA, (2) Adjusted EBITDA, (3) segment gross margin and (4) total segment gross margin. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense, and Adjusted EBITDA as EBITDA plus (i) depreciation and amortization expense of equity investees in proportion to our ownership interest in each such equity investee, and (ii) amortization expense attributable to the difference between our carried investment in each equity investee and our underlying equity in its net assets. We define segment gross margin as our operating segment’s revenue minus cost of sales. Cost of sales includes the: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs purchased by us from affiliates, costs we pay third parties to transport our volumes and costs we pay our affiliates to transport our volumes. We define total segment gross margin as the sum of our operating segments’ gross margins and the results of our risk management activities that are included in corporate and other. This measure is a key component of internal financial reporting and is used by our senior management in deciding how to allocate capital resources among operating segments. For a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read page 50 of this Annual Report.
 
The information in the following table is derived from, and should be read together with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included in Item 8 of this Annual Report. The selected financial information should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”
 
                                         
    Year Ended December 31,  
    2007(1)     2006     2005(2)     2004     2003  
    (In thousands, except per unit data)  
 
Summary of Operations Data:
                                       
Revenues
  $ 1,141,660     $ 860,272     $ 747,743     $ 437,656     $ 384,571  
Cost of sales
    934,726       672,184       643,652       386,155       353,376  
Operations and maintenance expenses
    41,156       32,484       18,459       12,486       10,854  
Depreciation and amortization
    39,967       31,993       17,052       7,287       6,091  
General and administrative expenses
    34,638       26,535       18,156       9,217       5,849  
Taxes other than income
    2,637       2,061       1,178       770       926  
Equity in (earnings) loss from unconsolidated affiliates(9)
    (2,850 )     (1,297 )     (927 )     (419 )     127  
                                         
Operating income
    91,386       96,312       50,173       22,160       7,348  
Interest income and other
    2,854       1,706       640       85       43  
Interest and other financing costs
    (29,351 )     (32,904 )     (20,461 )     (23,160 )     (12,108 )
                                         
Income before income taxes
    64,889       65,114       30,352       (915 )     (4,717 )
Provision for income taxes
    (1,714 )                        
                                         
Net income (loss)
  $ 63,175     $ 65,114     $ 30,352     $ (915 )   $ (4,717 )
                                         
Basic net income (loss) per common unit(3)
  $ 1.48     $ 1.77     $ 1.20     $ (0.17 )   $ (3.11 )
Diluted net income (loss) per common unit(3)
  $ 1.36     $ 1.75     $ 1.15     $ (0.17 )   $ (3.11 )


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    Year Ended December 31,  
    2007(1)     2006     2005(2)     2004     2003  
    (In thousands, except per unit data)  
 
Balance Sheet Data (at period end):
                                       
Total assets
  $ 1,769,083     $ 839,058     $ 792,750     $ 178,399     $ 161,709  
Property, plant and equipment, net
    694,727       566,927       532,320       119,683       117,032  
Payables to affiliates
    1,351       123       189       127       1,371  
Long-term debt
    630,773       255,000       398,000       57,000       57,898  
Redeemable preferred units
                            60,982  
Members’ capital
    894,136       472,586       281,803       82,356       (662 )
Cash Flow Data:
                                       
Net cash flow provided by (used in):
                                       
Operating activities
  $ 128,218     $ 91,679     $ 280     $ 17,697     $ 15,296  
Investing activities
    (727,052 )     (70,291 )     (491,708 )     (8,920 )     (6,192 )
Financing activities
    632,015       (7,201 )     509,710       (6,369 )     (9,633 )
Other Financial Data:
                                       
Total Segment Gross Margin:
                                       
Oklahoma(4)(5)
  $ 115,099     $ 95,614     $ 40,683     $     $  
Texas(6)(7)
    121,935       91,121       63,048       51,501       31,195  
Rocky Mountains(8)
    1,145                          
                                         
Segment gross margin
    238,179       186,735       103,731       51,501       31,195  
Corporate and other
    (31,245 )     1,353       360              
                                         
Total Segment gross margin
  $ 206,934     $ 188,088     $ 104,091     $ 51,501     $ 31,195  
                                         
EBITDA(9)
  $ 134,207     $ 130,011     $ 67,865     $ 29,532     $ 13,482  
                                         
Adjusted EBITDA(10)
  $ 140,626     $ 130,807     $ 68,285     $ 29,920     $ 13,831  
                                         
Maintenance capital expenditures(11)
  $ 9,062     $ 8,984     $ 5,394     $ 1,790     $ 2,281  
Expansion capital expenditures(12)
    884,290       53,298       487,578       7,130       3,911  
                                         
Total capital expenditures
  $ 893,352     $ 62,282     $ 492,972     $ 8,920     $ 6,192  
                                         
Cash distributions per common unit(3)
  $ 1.73     $ 1.29     $ 0.79     $ 0.51     $  
Operating Data:
                                       
Oklahoma:(4)(5)
                                       
Service throughput (Mcf/d)
    165,059       147,166       132,011              
Plant inlet volumes (Mcf/d)
    117,423       102,556       87,977              
NGLs produced (Bbls/d)
    13,771       11,811       9,146              
Crude pipeline throughput (Bbls/d)
    2,417                          
Texas:
                                       
Service throughput (Mcf/d)
    608,171       543,303       567,002       591,431       585,410  
Pipeline throughput (Mcf/d)(6)
    276,987       237,897       214,774       220,970       238,800  
Plant inlet volumes (Mcf/d)(6)(7)
    535,142       495,600       530,346       529,040       479,127  
NGLs produced (Bbls/d)(6)(7)
    17,496       14,740       13,066       15,373       7,280  
Rocky Mountains:
                                       
Producer services throughput (Mcf/d)(8)
    232,169                          
 
 
(1) Our summary financial and operating data as of and for the year ended December 31, 2007 include results attributable to our Cimmarron from May 1, 2007 through December 31, 2007 and Cantera from October 1, 2007 through December 31, 2007.
 
(2) Our summary financial and operating data as of and for the year ended December 31, 2005 include the results of our Oklahoma segment from August 1, 2005 (the date we acquired ScissorTail) through December 31, 2005.
 
(3) Net income (loss) per unit is based on the weighted average of total equivalent units outstanding during the periods presented. Prior periods have been adjusted to reflect the two-for-one split of our outstanding common units effective March 30, 2007. For periods prior to our IPO, equivalent units were calculated using the weighted average of pre-IPO common units and common special units adjusted by a conversion or exchange factor. The computation of diluted units outstanding for 2004 and 2003 excludes incremental units related to warrants previously held by preferred unitholders and employee unit options because these equity securities

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had an anti-dilutive effect as a result of losses reported by us for these periods. Cash distributions for 2004 relate to the distributions paid to the pre-IPO unitholders prior to our IPO and are based on equivalent units.
 
(4) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including our own plants and plants owned by third parties. For the year ended December 31, 2007, plant inlet volumes averaged 76,041 Mcf/d and NGLs produced averaged 9,349 Bbls/d for plants owned by the Oklahoma segment. For the year ended December 31, 2006, plant inlet volumes averaged 67,131 Mcf/d and NGLs produced averaged 7,989 Bbls/d for plants owned by the Oklahoma segment.
 
(5) Excludes volumes associated with our interest in Southern Dome. For the year ended December 31, 2007, plant inlet volumes for Southern Dome averaged 5,093 Mcf/d and NGLs produced averaged 244 Bbls/d. For the year ended December 31, 2006, plant inlet volumes for Southern Dome averaged 2,004 Mcf/d and NGLs produced averaged 88 Bbls/d.
 
(6) Excludes volumes associated with our interest in Webb Duval. Volumes transported by Webb Duval, net of intercompany volumes, were 82,755 Mcf/d, 102,691 Mcf/d, 106,826 Mcf/d, 104,438 Mcf/d, and 95,341 Mcf/d for the years ended December 31, 2007, 2006, 2005, 2004 and 2003, respectively.
 
(7) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 523,044 Mcf/d and NGLs produced averaged 16,317 barrels per day for the year ended December 31, 2007 for plants owned by the Texas segment. Plant inlet volumes averaged 495,600 Mcf/d and NGLs produced averaged 14,740 barrels per day for the year ended December 31, 2006 for plants owned by the Texas segment.
 
(8) Producer services throughput represents volumes we purchased for resale, volumes gathered utilizing our firm capacity gathering agreements with Fort Union and firm capacity volumes under our transportation agreements with WIC that we have released to producers in the Powder River Basin. Excludes results and volumes associated with our interests in Bighorn and Fort Union. Volumes transported by Bighorn and Fort Union were 216,584 Mcf/d and 604,850 Mcf/d, respectively, for the period from October 1, 2007 through December 31 2007.
 
(9) Under the equity method of accounting, these amounts include our equity in the (earnings) loss in affiliates.
 
(10) We calculate Adjusted EBITDA by adding to EBITDA (i) the portion of each of our equity investees’ depreciation and amortization expense that is proportional to our ownership interest in each such equity investee, and (ii) the amortization expense attributable to the difference between our carried investment in each equity investee and our underlying equity in its net assets. We use Adjusted EBITDA to reflect the depreciation and amortization expense embedded in equity in earnings (loss) from unconsolidated affiliates. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.
 
(11) Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.
 
(12) Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. For example, expansion of compression facilities to increase throughput capacity or the acquisition of additional pipelines is considered expansion capital expenditures. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. Costs for repairs and minor renewals to maintain facilities in operating condition, and which do not extend the useful life of existing assets, are considered operations and maintenance expenses (and not expansion capital expenditures) and are expensed as incurred.


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The following table presents a reconciliation of the non-GAAP financial measures of (i) total segment gross margin (which consists of the sum of the segment gross margins of our three operating segments and corporate and other) to operating income and (ii) EBITDA and Adjusted EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities on a historical basis for each of the periods indicated. For a detailed discussion of how we use these non-GAAP financial measures, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — How We Evaluate Our Operations — Segment Gross Margin and — Adjusted EBITDA.”
 
                                         
    Year Ended December 31,  
    2007     2006     2005     2004     2003  
    (In thousands)  
 
Reconciliation of total segment gross margin to operating income:
                                       
Operating income
  $ 91,386     $ 96,312     $ 50,173     $ 22,160     $ 7,348  
Add:
                                       
Operations and maintenance expenses
    41,156       32,484       18,459       12,486       10,854  
Depreciation and amortization
    39,967       31,993       17,052       7,287       6,091  
General and administrative expenses
    34,638       26,535       18,156       9,217       5,849  
Taxes other than income
    2,637       2,061       1,178       770       926  
Equity in (earnings) loss from unconsolidated affiliates
    (2,850 )     (1,297 )     (927 )     (419 )     127  
                                         
Total segment gross margin
  $ 206,934     $ 188,088     $ 104,091     $ 51,501     $ 31,195  
                                         
Reconciliation of EBITDA and adjusted EBITDA to net income (loss):
                                       
Net income (loss)
  $ 63,175     $ 65,114     $ 30,352     $ (915 )   $ (4,717 )
Add:
                                       
Depreciation and amortization
    39,967       31,993       17,052       7,287       6,091  
Interest and other financing costs
    29,351       32,904       20,461       23,160       12,108  
Provision for income taxes
    1,714                          
                                         
EBITDA
  $ 134,207     $ 130,011     $ 67,865     $ 29,532     $ 13,482  
Add:
                                       
Amortization of difference between the carried investment and the underlying equity in net assets of equity investments
    4,589       (14 )     (21 )     (21 )     (21 )
Copano’s share of depreciation and amortization included in equity in (earnings) loss from unconsolidated affiliates
    1,830       810       441       409       370  
                                         
Adjusted EBITDA
  $ 140,626     $ 130,807     $ 68,285     $ 29,920     $ 13,831  
                                         
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
                                       
Cash flow provided by operating activities
  $ 128,218     $ 91,679     $ 280     $ 17,697     $ 15,296  
Add:
                                       
Cash paid for interest and other financing costs
    27,685       28,442       14,738       4,029       3,033  
Equity in earnings (loss) from unconsolidated affiliates
    2,850       1,297       927       419       (127 )
Distributions from unconsolidated affiliates
    (3,706 )                        
Risk management assets
    21,720       23,014       42,635              
(Increase) decrease in working capital and other
    (42,560 )     (14,421 )     9,285       7,387       (4,720 )
                                         
EBITDA
  $ 134,207     $ 130,011     $ 67,865     $ 29,532     $ 13,482  
Add:
                                       
Amortization of difference between the carried investment and the underlying equity in net assets of equity investments
    4,589       (14 )     (21 )     (21 )     (21 )
Copano’s share of depreciation and amortization included in equity in (earnings) loss from unconsolidated affiliates
    1,830       810       441       409       370  
                                         
Adjusted EBITDA
  $ 140,626     $ 130,807     $ 68,285     $ 29,920     $ 13,831  
                                         


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operation
 
You should read the following discussion of our financial condition and results of operation in conjunction with the historical consolidated financial statements and notes thereto included elsewhere in this Annual Report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical consolidated financial statements included in Item 8 of this Annual Report. In addition, you should review “— Forward-Looking Statements” contained in this Item 7 of this Annual Report and “— Risk Factors” contained in Item 1A of this Annual Report for information regarding forward-looking statements made in this discussion and certain risks inherent in our business. Other risks involved in our business are discussed under Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”
 
Overview
 
We are a Delaware limited liability company formed in 2001 to acquire entities operating under the Copano name since 1992, and to serve as a holding company for our operating subsidiaries. Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission pipeline assets and natural gas processing facilities in central and eastern Oklahoma and Texas, and as a result of the Cantera acquisition in October 2007, in Wyoming and Louisiana.
 
We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments, Oklahoma, Texas and Rocky Mountains.
 
  •  Our Oklahoma segment provides midstream natural gas services in central and eastern Oklahoma, including gathering and related compression and dehydration services and natural gas processing, and was established as a segment upon our acquisition of ScissorTail on August 1, 2005. For the years ended December 31, 2007 and 2006, this segment generated approximately 56% and 51%, respectively, of our total segment gross margin.
 
  •  Our Texas segment provides midstream natural gas services in southeastern and northern Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration and marketing. Our Texas segment also provides natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central plant, Sheridan NGL pipeline and, beginning in 2008, our Brenham NGL pipeline. In addition, our Texas segment owns a processing plant located in southwestern Louisiana. For the years ended December 31, 2007 and 2006, this segment generated approximately 58% and 48%, respectively, of our total segment gross margin.
 
  •  Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. The Rocky Mountains segment was established as a segment as a result of our acquisition of Cantera in October 2007. For the years ended December 31, 2007 and 2006, this segment generated approximately 1% and 0%, respectively, of our total segment gross margin, which represents margins derived from our producer services. The gross margin generated by this segment does not include results associated with our interests in Bighorn or Fort Union, which are reported as equity in earnings (loss) from unconsolidated affiliates.
 
Corporate and other relate to our risk management activities, intersegment eliminations, and other activities we perform or assets we hold that have not been allocated to any of our reporting segments. For the years ended December 31, 2007 and 2006, corporate and other generated approximately (15)% and 1%, respectively, of our total segment gross margin. Total segment gross margin is a non-GAAP financial measure, and includes the sum of our operating segments’ gross margin and the results of our risk management activities that are included in corporate and other. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read Item 6 “Selected Financial Data.”
 
Our total segment gross margins are determined primarily by five interrelated variables: (1) the volume of natural gas gathered or transported through our pipelines, (2) the volume of natural gas processed, conditioned or treated at our processing plants or, on our behalf, at third-party processing plants, (3) the level and relationship of natural gas and NGL prices, (4) our current contract portfolio and (5) our risk management activities. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues


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from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. For a summary of our most common contractual arrangements and management’s analysis of our recent results of operations, please read “— Our Contracts” and “— Our Results of Operation.” Our profitability is also dependent upon prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.
 
Our Oklahoma unit margins are, on the whole, positively correlated with NGL prices and natural gas prices. Increases in natural gas prices or decreases in NGL prices generally have a negative impact on our Texas unit margins, and, conversely, a reduction in natural gas prices or an increase in NGL prices generally has a positive impact on our Texas unit margins. The profitability of our Rocky Mountains operations is not significantly affected by the level of commodity prices. Substantially all of our Rocky Mountains contract portfolio, as well as Bighorn’s and Fort Union’s contract portfolios, consist of fixed-fee arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. The revenue we earn as a result of these arrangements is directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues under these arrangements would be reduced.
 
How We Evaluate Our Operations
 
We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our performance. Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) throughput volumes; (2) segment gross margin; (3) operations and maintenance expenses; (4) general and administrative expenses; (5) EBITDA; (6) Adjusted EBITDA and (7) distributable cash flow.
 
Throughput Volumes.  Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes coming into our plants and moving on our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is significantly influenced by both the volume of natural gas coming into the plant and the NGL content of the natural gas. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs associated with our pipeline operations, these costs are frequently passed on to our producers.
 
It is also important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes that are attached to those systems. In monitoring volumes on our pipelines, managers of our Oklahoma and Texas segments evaluate what we refer to as service throughput, which consists of two components:
 
  •  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.
 
In our Texas segment, we also compare pipeline throughput to service throughput to evaluate the volumes generated from our pipelines, as opposed to third-party pipelines. In Oklahoma, because no gas is delivered to our wholly owned plants other than by our pipelines, pipeline throughput and service throughput are equivalent. We also regularly assess the pipeline throughput of Bighorn and Fort Union.
 
In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered utilizing our firm capacity gathering agreements with Fort Union and firm capacity volumes under our transportation agreements with WIC that we have released to producers.
 
Segment Gross Margin.  We define segment gross margin as our operating segment’s revenue minus cost of sales. Cost of sales includes the: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas


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and NGLs purchased by us from affiliates, costs we pay third parties to transport our volumes and costs we pay our affiliates to transport our volumes. We define total segment gross margin as the sum of our operating segments’ gross margins and the results of our risk management activities that are included in corporate and other. We view segment gross margin as an important performance measure of the core profitability of our operations. The total segment gross margin data reflects the financial impact of our contract portfolio on our company. This measure is a key component of internal financial reporting and is used by our senior management in deciding how to allocate capital resources among operating segments. With respect to our Oklahoma and Texas segments, our management analyzes segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn and Fort Union. Both our segment gross margin and total segment gross margin is reviewed monthly for consistency and trend analysis.
 
To isolate and consistently track changes in commodity price relationships and their impact on our Texas segment’s results from its processing operations, we calculate a hypothetical “standardized” processing margin. This processing margin is based on a fixed set of assumptions, with respect to liquids composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our financial results are not derived from this standardized processing margin and the standardized margin is not derived from our financial results. However, we believe this calculation is representative of the current operating commodity price environment of our Texas processing operations and we use this calculation to track commodity price relationships. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices such as volumes, changes in NGL composition, recovery rates and variable contract terms. Our standardized processing margins averaged $0.4578, $0.2808 and $0.0899 per gallon during the years ended December 31, 2007, 2006 and 2005, respectively. The average standardized processing margin for the period from January 1, 1989 through December 31, 2007 is $0.12 per gallon.
 
Operations and Maintenance Expenses.  Operations and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, insurance, repair and maintenance, utilities and contract services comprise the most significant portion of operations and maintenance expenses. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. A portion of our operations and maintenance expenses are incurred through Copano Operations, an affiliate of our company and controlled by John R. Eckel, Jr., the Chairman of our Board of Directors and our Chief Executive Officer. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the operations and maintenance expenses it incurs on our behalf, which consist primarily of payroll costs.
 
General and Administrative Expenses.  Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. A portion of our general and administrative expenses are incurred through Copano Operations, an affiliate of our company. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the general and administrative expenses it incurs on our behalf. For more information concerning our arrangement with Copano Operations, please see Note 9, “Related Party Transactions” to the consolidated financial statements beginning on page F-1 of this Annual Report.
 
Adjusted EBITDA.  We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which now include Big Horn and Fort Union in addition to Webb Duval and Southern Dome), our management also calculates Adjusted EBITDA to reflect the depreciation and amortization expense embedded in equity in earnings (loss) from unconsolidated affiliates. Specifically, our management determines Adjusted EBITDA by adding to EBITDA (i) the portion of each equity investee’s depreciation and amortization expense which is proportional to our ownership interest in that equity investee and (ii) the amortization expense attributable to the difference between our carried investment in each equity investee and our underlying equity in its net assets.


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External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or Adjusted EBITDA, and our management uses Adjusted EBITDA, as a supplemental financial measure to assess:
 
  •  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.
 
EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to our lenders and is used to compute our financial covenants under our senior secured revolving credit facility. Neither EBITDA nor Adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.
 
Distributable Cash Flow.  We define distributable cash flow as net income or loss plus: (i) depreciation and amortization expense; (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) reimbursements by our pre-IPO investors of certain general and administrative expenses in excess of the “G&A Cap” defined in our limited liability company agreement; (iv) the subtraction of maintenance capital expenditures, (v) the subtraction of equity in earnings from unconsolidated affiliates and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the market value of a unit of such an entity is significantly influenced by the amount of cash distributions the entity can pay to a unitholder.
 
How We Manage Our Operations
 
Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models; (ii) flow and transaction monitoring systems (iii) producer activity evaluation and reporting; and (iv) imbalance monitoring and control.
 
Our Economic Models.  We utilize our economic models to determine (i) whether we should elect payment using a percentage-of-index basis or a percentage-of-proceeds basis under certain Oklahoma “switch” contracts, which allow us to choose the basis of payment (ii) whether we should reduce the ethane extracted from certain natural gas processed by some of our processing plants and (iii) whether we should process or condition natural gas at our Houston Central plant.
 
Flow and Transaction Monitoring Systems.  We utilize automated systems that track commercial activity on each of our Texas segment pipelines and monitor the flow of natural gas on all of our pipelines. For our Oklahoma segment, we electronically monitor pipeline volumes and operating conditions at certain key points along our pipeline systems. In our Texas segment, we designed and implemented software that tracks each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our


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pipeline assets. Additionally, we utilize automated Supervisory Control and Data Acquisition (SCADA) systems, which assists management in monitoring and operating our Texas segment. Bighorn, which our Rocky Mountains segment operates, also utilizes a SCADA system. The SCADA systems allow us to monitor our assets at remote locations and respond to changes in pipeline operating conditions.
 
Producer Activity Evaluation and Reporting.  We monitor the producer drilling and completion activity in our Texas and Oklahoma areas of operation to identify anticipated changes in production and potential new well attachment opportunities. The continued attachment of natural gas production to our pipeline systems is critical to our business and directly impacts our financial performance. Using a third-party electronic reporting system, we receive daily reports of new drilling permits and completion reports filed with the state regulatory agency that governs these activities in Texas and Oklahoma. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel. These processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines. In all our operating segments, we meet with producers and obtain drilling schedules, if available, to assist us in anticipating future activity on our pipelines.
 
Imbalance Monitoring and Control.  We continually monitor volumes received and volumes delivered on behalf of third parties to ensure we remain within acceptable imbalance limits during the calendar month. We seek to reduce imbalances because of the inherent commodity price risk that results when receipts and deliveries of natural gas are not balanced concurrently. We have implemented “cash-out” provisions in many of our transportation agreements to reduce this commodity price risk. Cash-out provisions require that any imbalance that exists between a third party and us at the end of a calendar month is settled in cash based upon a pre-determined pricing formula. This provision ensures that imbalances under such contracts are not carried forward from month-to-month and revalued at higher or lower prices.
 
Our Contracts
 
In connection with our operations, we seek to execute contracts with producers and shippers that provide us with positive gross margin in all natural gas and NGL pricing environments. We enter into a variety of contractual arrangements, including fee-based arrangements, percentage-of-proceeds arrangements, percentage-of-index arrangements and keep-whole with fee arrangements. Actual contract terms vary based upon a variety of factors including gas quality, pressures of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, gas quality, downstream transporter gas quality specifications, our expansion in regions where some types of contracts are more common and other market factors.
 
The following is a summary of our most common contractual arrangements for gathering, transporting, processing and conditioning natural gas:
 
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. The revenue we earn from fixed-fee arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. When the fee is based upon a percentage of index price, the fee decreases in periods of low natural gas prices and increases during periods of high natural gas prices.
 
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. Under these types of arrangements, our revenues and gross margins increase as natural gas and NGL prices increase and our revenues and gross margins decrease as natural gas and NGL prices decrease.


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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. The gross margins we realize under the arrangements described in clauses (i) and (iii) above decrease in periods of low natural gas prices and increase during months of high natural gas prices because these gross margins are based on a percentage of the index price.
 
Keep-Whole with Fee Arrangements.  Under keep-whole with fee arrangements, we receive natural gas from producers and third-party transporters, either process or condition the natural gas at our election, sell the resulting NGLs to third parties at market prices for our account and redeliver the residue gas to the producer or third-party transporter. We determine whether to process or condition the natural gas based upon the relationship between natural gas and NGL prices. Because the extraction of NGLs from the natural gas during processing or conditioning reduces the Btus of the natural gas, we also must purchase natural gas at market prices for return to producers or third-party transporters to keep them whole. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, we are generally able to reduce our commodity price exposure by conditioning rather than processing the natural gas. 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. For a discussion of our processing and conditioning capabilities, please read Item 1, “Business — Our Operations — Texas” of this Annual Report. In our Oklahoma and Texas segments, we often provide services under contracts that reflect a combination of these contract types, while substantially all of our Rocky Mountains segment’s contracts reflect fixed-fee arrangements. Fort Union’s and Bighorn’s contractual arrangements are entirely fixed-fee.
 
In addition to providing for compensation for our gathering, transportation, processing or conditioning services, in many cases, our contracts for natural gas supplies also allow us to charge producers fees for treating, compression, dehydration or other services. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter in the form of “processing upgrade” payments during periods where such margins are in excess of an agreed-upon amount.
 
Our Contracts with Kinder Morgan Texas Pipeline.  We use KMTP as a transporter because our Houston Central plant straddles its 30-inch-diameter Laredo-to-Katy pipeline, which allows us to move natural gas from our pipeline systems in South Texas and near the Texas Gulf Coast to our Houston Central plant and downstream markets. KMTP’s pipeline also delivers to the Houston Central plant natural gas for its own account, which we refer to as “KMTP Gas.” Under agreements with KMTP and with other producers or transporters whose gas KMTP has delivered to us, we process or condition the gas and sell the NGLs to third parties at market prices. Under our processing agreement with KMTP, after processing or conditioning KMTP Gas, we make up for the reduction in Btus resulting from extracting NGLs from the natural gas stream using natural gas that we purchase from producers at market prices Our processing agreement with KMTP also provides that we make a processing payment to KMTP during periods of favorable processing margins, which allows KMTP to share in the profitability of processing gas. During periods of unfavorable processing margins, KMTP instead pays us the lesser of (i) the difference between the processing margin and a specified threshold or (ii) a fixed fee per Mcf of KMTP Gas.
 
We also have a gas transportation agreement and a related gas sales agreement with KMTP. Each of our agreements with KMTP extends through January 31, 2011, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior written notice, in the case of the processing and gas transportation agreements, or 30 days’ prior written notice, in the case of the sales agreement.
 
For the year ended December 31, 2007, approximately 76% of the natural gas volumes processed or conditioned at our Houston Central plant were delivered to the plant through the KMTP Laredo-to-Katy pipeline, while the remaining 24% were delivered directly to the plant from our Houston Central gathering systems. Of the volumes delivered from the KMTP Laredo-to-Katy pipeline, approximately 31% were from our


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gathering systems, while 69% were “KMTP Gas.” Of the total NGLs extracted at the plant during this period, 32% originated from KMTP Gas, and 68% from our South Texas gathering systems, including our gathering systems connected directly to the plant.
 
Our Long-Term Growth Strategy
 
Our growth strategy contemplates complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. We intend to pursue acquisitions and capital expenditure projects that we believe will allow us to capitalize on our existing infrastructure, personnel and relationships with producers and customers to provide midstream services. We also evaluate acquisitions in new geographic areas, including other areas of Texas, Oklahoma and New Mexico and the Rocky Mountains region, to the extent they present growth opportunities similar to those we are pursuing in our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms. We believe that our long-term cost of equity capital will be favorable because unlike many of our competitors that are master limited partnerships, or MLPs, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as higher per unit levels of cash distributions are received. We intend to finance future acquisitions primarily through the issuance of debt and equity. For a more detailed discussion of our capital resources, please read “— Liquidity and Capital Resources.”
 
Acquisition Analysis.  In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets, strategic fit of the assets in relation to our business strategy, expertise required to manage the assets, capital required to integrate and maintain the assets, and the competitive environment of the area where the assets are located. From a financial perspective, we analyze the rate of return the assets will generate under various case scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.
 
Capital Expenditure Analysis.  We make capital expenditures either to maintain our assets or the supply of natural gas volumes to our assets or for expansion projects to increase our gross margin. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. 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. Our decisions whether to spend capital on expansion projects are generally based on anticipated earnings, cash flow and rate of return of the assets.
 
Items Impacting Comparability of Our Financial Results
 
Our Acquisitions
 
Since our inception in 1992, we have grown through a combination of numerous acquisitions, including the acquisition of our Oklahoma and Rocky Mountains segments, as well as significant expansion and enhancement projects related to our assets. Our historical acquisitions were completed at different dates and with a number of sellers and were accounted for using the purchase method of accounting. Under the purchase method of accounting, results of operations from such acquisitions are recorded in the financial statements only from the date of acquisition. As a result, our historical results of operations for the periods presented may not be comparable, as they reflect the results of operations of a business that has grown significantly due to acquisitions. For example, the year ended December 31, 2005 is not comparable to the years ended December 31, 2006 and 2007 because of our acquisition of ScissorTail in August 2005 (which comprised our entire Oklahoma segment until our acquisition of Cimmarron in May 2007) and the years ended December 31, 2005 and 2006 are not comparable to the year ended December 31, 2007 because of our acquisitions of Cimmarron in May 2007 and Cantera in October 2007.


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Adoption of SFAS No. 123(R)
 
On January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R) which requires the grant date fair value of the equity compensation award to be recognized as expense over the vesting period of the award. We have elected to use the modified prospective method and accordingly, results for prior periods were not restated. Prior to the adoption of SFAS No. 123(R), we recognized equity-based compensation expense for awards with graded vesting by treating each vesting tranche as a separate award and recognizing compensation expense ratably for each tranche. For equity awards outstanding as of January 1, 2006, the remaining unrecognized compensation expense as of January 1, 2006 is expensed on a straight-line basis (net of estimated forfeitures) over the remaining vesting period of the award. We treat equity awards granted after the adoption of SFAS No. 123(R), as a single award and recognize equity-based compensation expense on a straight-line basis (net of estimated forfeitures) over the employee service or vesting period. Equity-based compensation expense is recorded in operations and maintenance expenses and general and administrative expenses in our consolidated statements of operations. The adoption of this statement did not have a material effect on our financial position or results of operations. Please read Notes 2 and 8 to the Consolidated Financial Statements contained in Item 8 of this Annual Report.
 
Our Results of Operation
 
                         
    Year Ended December 31,  
    2007(1)     2006     2005(2)  
    ($ in thousands)  
 
Total segment gross margin(3)
  $ 206,934     $ 188,088     $ 104,091  
Operations and maintenance expenses
    41,156       32,484       18,459  
Depreciation and amortization
    39,967       31,993       17,052  
General and administrative expenses
    34,638       26,535       18,156  
Taxes other than income
    2,637       2,061       1,178  
Equity in earnings from unconsolidated affiliates
    (2,850 )     (1,297 )     (927 )
                         
Operating income
    91,386       96,312       50,173  
Interest and other financing costs, net
    (26,497 )     (31,198 )     (19,821 )
                         
Income before income taxes
    64,889       65,114       30,352  
Provision for income taxes
    (1,714 )            
                         
Net income
  $ 63,175     $ 65,114     $ 30,352  
                         
Total segment gross margin:
                       
Oklahoma(4)(5)
  $ 115,099     $ 95,614     $ 40,683  
Texas(6)(7)
    121,935       91,121       63,048  
Rocky Mountains(8)
    1,145              
                         
Segments gross margin
    238,179       186,735       103,731  
Corporate and other
    (31,245 )     1,353       360  
                         
Total segment gross margin(3)
  $ 206,934     $ 188,088     $ 104,091  
                         
Segment gross margin per unit:
                       
Oklahoma:
                       
Service throughput ($/MMBtu)(4)(5)
  $ 1.580     $ 1.48     $ 1.68  
Texas:
                       
Service throughput ($/MMBtu)(6)(7)
  $ 0.520     $ 0.44     $ 0.29  
Rocky Mountains:
                       
Producer services throughput ($/MMBtu)(8)
  $ 0.055              


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    Year Ended December 31,  
    2007(1)     2006     2005(2)  
    ($ in thousands)  
 
Volumes:
                       
Oklahoma:(4)(5)
                       
Service throughput (MMBtu/d)
    199,906       177,368       158,334  
Plant inlet volumes (MMBtu/d)
    144,050       125,364       106,877  
NGLs produced (Bbls/d)
    13,771       11,811       9,146  
Crude pipeline throughput (Bbls/d)
    2,417              
Texas:
                       
Service throughput (MMBtu/d)
    645,724       573,141       597,888  
Pipeline throughput (MMBtu/d)(6)
    299,484       254,886       232,280  
Plant inlet volumes (MMBtu/d)(6)(7)
    567,306       522,465       561,085  
NGLs produced (Bbls/d)(6)(7)
    17,496       14,740       13,066  
Rocky Mountains:
                       
Producer services throughput (MMBtu/d)(8)
    224,525              
                         
Maintenance capital expenditures(9)
  $ 9,062     $ 8,984     $ 5,394  
Expansion capital expenditures(10)
    884,290       53,298       487,578  
                         
Total capital expenditures
  $ 893,352     $ 62,282     $ 492,972  
                         
Operations and maintenance expenses:
                       
Oklahoma
  $ 20,711     $ 17,185     $ 5,917  
Texas
    20,437       15,299       12,542  
Rocky Mountains
    8              
                         
Total operations and maintenance expenses
  $ 41,156     $ 32,484     $ 18,459  
                         
 
 
(1) Our summary financial and operating data for the year ended December 31, 2007 include results attributable to Cimmarron acquisition from May 1, 2007 through December 31, 2007 and Cantera (which comprises our entire Rocky Mountains segment) from October 1, 2007 through December 31, 2007. The results of operations from assets acquired in the Cimmarron acquisition are included in the Oklahoma segment and Texas segments.
 
(2) Our summary financial and operating data for the year ended December 31, 2005 include the results of our Oklahoma segment from August 1, 2005 the date we acquired ScissorTail) through December 31, 2005.
 
(3) Total segment gross margin is a non-GAAP financial measure. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read Item 6 “Selected Financial Data” of this Annual Report.
 
(4) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including our owned plants and plants owned by third parties. For the year ended December 31, 2007, Plant inlet volumes averaged 93,173 MMBtu/d and NGLs produced averaged 9,349 Bbls/d for plants owned by the Oklahoma segment. For the year ended December 31, 2006, plant inlet volumes averaged 82,045 MMBtu/d and NGLs produced averaged 7,989 Bbls/d for plants owned by the Oklahoma segment.
 
(5) Excludes volumes associated with our interest in Southern Dome. For the year ended December 31, 2007, plant inlet volumes for Southern Dome averaged 6,061 MMBtu/d and NGLs produced averaged 244 Bbls/d. For the year ended December 31, 2006, plant inlet volumes for Southern Dome averaged 2,353 MMBtu/d and NGLs produced averaged 88 Bbls/d.

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(6) Excludes results and volumes associated with our interest in Webb Duval. Volumes transported by Webb Duval, net of intercompany volumes, were 93,887 MMBtu/d, 117,303 MMBtu/d and 121,864 MMBtu/d for the years ended December 31 2007, 2006 and 2005, respectively.
 
(7) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 552,690 MMBtu/d and NGLs produced averaged 16,317 barrels per day for the year ended December 31, 2007 for plants owned by the Texas segment. Plant inlet volumes averaged 522,465 MMBtu/d and NGLs produced averaged 14,740 barrels per day for the year ended December 31, 2006 for plants owned by the Texas segment.
 
(8) Producer services throughput represents volumes we purchased for resale, volumes gathered utilizing our firm capacity gathering agreements with Fort Union and firm capacity volumes under our transportation agreements with WIC that we have released to producers in the Powder River Basin. Excludes results and volumes associated with our interests in Bighorn and Fort Union. Volumes transported by Bighorn and Fort Union were 211,510 MMBtu/d and 576,700 MMBtu/d, respectively, for the period from October 1, 2007 through December 31 2007.
 
(9) Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.
 
(10) Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. For example, expansion of compression facilities to increase throughput capacity or the acquisition of additional pipelines is considered expansion capital expenditures. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. Costs for repairs and minor renewals to maintain facilities in operating condition, and which do not extend the useful life of existing assets, are considered operations and maintenance expenses (and not expansion capital expenditures) and are expensed as incurred.
 
(11) Under the equity method of accounting, these amounts include our equity in the (earnings) loss in affiliates.
 
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
 
Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $115.1 million for the year ended December 31, 2007 compared to $95.6 million for the year ended December 31, 2006, an increase of $19.5 million, or 20%. The increase in segment gross margin resulted primarily from increases in NGLs produced, plant inlet volumes and service throughput of 17%, 15% and 13%, respectively, and higher NGL prices. The Cimmarron assets included in the Oklahoma segment accounted for 8% of the increase in NGLs produced, 12% of the increase in Plant inlet volumes and 11% of the increased service throughput for this segment. NGLs produced at the Paden plant increased 22% during 2007 as compared to 2006. Throughput on the crude oil system acquired in May 2007 as part of the Cimmarron acquisition averaged 3,600 barrels per day for the period from May 1, 2007 through December 31, 2007. During 2007, the CenterPoint East natural gas index price averaged $6.07 per MMBtu compared to $6.15 per MMBtu during 2006, a decrease of $0.08, or 1.3%.
 
Texas Segment Gross Margin.  Texas segment gross margin was $121.9 million for the year ended December 31, 2007 compared to $91.1 million for year ended December 31, 2006, an increase of $30.8 million, or 34%. The increase was primarily attributable to increased service throughput and improvements of $26.5 million attributable to increased NGL margins and output at our Houston Central plant. During year ended December 31, 2007, the HSC natural gas index price averaged $6.58 per MMBtu compared to $6.53 per MMBtu during the year ended December 31, 2006, an increase of $0.05, or 1%. For a discussion of the commodity price environment affecting our Texas segment, please read “— How We Evaluate Our Operations — Segment Gross Margin.”
 
Rocky Mountains Segment Gross Margin.  From our acquisition of the Rocky Mountains segment in October 2007 through December 31, 2007, the segment gross margin totaled $1.1 million. During this period, producer


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services throughput averaged 224,525 MMBtu/d with an average margin of $0.055 per MMBtu. Producer services throughput represents volumes we purchased for resale, volumes gathered utilizing our firm capacity gathering agreements with Fort Union and firm capacity volumes under our transportation agreements with WIC that we have released to producers in the Powder River Basin.
 
Corporate and Other.  The corporate and other loss includes our commodity risk management activities of $31.2 million for the year ended December 31, 2007 compared to a gain of $1.4 million for the year ended December 31, 2006. The loss for the year ended December 31, 2007 is comprised of $21.0 million of non-cash amortization expense related to purchased commodity derivatives and $10.1 million of unrealized losses related to mark-to-market changes and ineffective portions of hedges and $0.1 million of net cash settlements paid with respect to expired commodity derivatives. The gain for the year ended December 31, 2006 consisted of (i) $12.1 million of net cash settlements on expired commodity derivatives offset by (ii) $10.4 million of non-cash amortization expense related to purchased commodity derivatives and $0.3 million of unrealized losses related to the ineffective portion of hedges.
 
Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $41.2 million for the year ended December 31, 2007 compared to $32.5 million for the year ended December 31, 2006. The increase of $8.7 million, or 27%, is primarily attributed to (i) increased labor, compression, insurance, materials and supplies and repair expenses in our Oklahoma segment of $3.5 million including activities associated with the Cimmarron assets acquired in May 2007 and (ii) increased labor, chemicals, utilities, lease rentals and repair and maintenance expenses of $5.2 million in our Texas segment including activities associated with the Tri-County assets acquired in May 2007 as part of Cimmarron.
 
Depreciation and Amortization.  Depreciation and amortization totaled $40.0 million for the year ended December 31, 2007 compared with $32.0 million for the year ended December 31, 2006, an increase of $8.0 million, or 25%. This increase relates primarily to additional depreciation and amortization associated with acquisitions and capital expenditures made after December 31, 2006, including the Cimmarron acquisition in May 2007 and the Cantera acquisition in October 2007.
 
General and Administrative Expenses.  General and administrative expenses totaled $34.6 million for the year ended December 31, 2007 compared with $26.5 million for the year ended December 31, 2006, an increase of $8.1 million, or 30%. The increase primarily relates to (i) expenses related to additional personnel, consultants and office space and compensation adjustments of $4.5 million, (ii) expenses incurred by our Oklahoma segment of $1.6 million including expenses related to Cimmarron assets acquired in May 2007, (iii) legal and accounting fees of $1.1 million, (iv) non-cash compensation expense related to the amortization of the fair value of restricted units, phantom units and unit options issued to employees and directors of $0.7 million, (v) costs associated with the Rocky Mountains segment acquired in October 2007 of $0.6 million and (vi) costs of preparing and processing tax K-1s to unitholders of $0.4 million offset by a decrease of $0.8 million related to expenses associated with acquisition initiatives that were not consummated.
 
Interest Expense.  Interest and other financing costs totaled $29.4 million for the year ended December 31, 2007 compared with $32.9 million for the year ended December 31, 2006, a decrease of $3.5 million, or 11%. Interest expense related to our senior secured revolving credit facility totaled $8.2 million (net of $1.2 million of capitalized interest and settlements under our interest rate swaps) and $8.8 million (net of $1.0 million of capitalized interest and settlements under our interest rate swaps) for the year ended December 31, 2007 and 2006, respectively. Interest on our Senior Notes totaled $19.5 million and $16.5 million for the year ended December 31, 2007 and 2006, respectively. Interest on our unsecured term loan and our term loan facility totaled $3.1 million for the year ended December 31, 2006. Amortization of debt issue costs totaled $1.7 million and $4.5 million for the year ended December 31, 2007 and 2006, respectively. Amortization of debt issue costs for the year ended December 31, 2006 included a one-time charge of $1.7 million related to the reduction of the commitment under the Credit Facility from $350 million to $200 million. Average borrowings under our credit arrangements were $376.5 million and $373.2 million with average interest rates of 7.9% and 8.3% for the year ended December 31, 2007 and 2006, respectively. Please read “— Liquidity and Capital Resources — Description of Our Indebtedness” for a detailed discussion of our senior secured revolving credit facility and our Senior Notes.


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Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
 
Oklahoma Segment Gross Margin.  For the year ended December 31, 2006, segment gross margin for our Oklahoma segment totaled $95.6 million. During the same period, this segment gathered or transported an average of 177,368 MMBtu/d of natural gas on its pipelines, processed an average of 125,364 MMBtu/d of natural gas and produced an average of 11,811 Bbls/d of NGLs. Our Oklahoma segment was established upon our acquisition of ScissorTail on August 1, 2005 and during the period from August 1, 2005 through December 31, 2005, segment gross margin for our Oklahoma segment totaled $40.7 million. During the same period, this segment gathered or transported an average of 158,334 MMBtu/d of natural gas on its pipelines, processed an average of 106,877 MMBtu/d of natural gas and produced an average of 9,146 Bbls/d of NGLs.
 
Texas Segment Gross Margin.  Texas segment gross margin was $91.1 million for the year ended December 31, 2006 compared to $63.0 million for the year ended December 31, 2005, an increase of $28.1 million, or 45%. This increase resulted from a 10% increase in pipeline throughput during the year ended December 31, 2006 and improvements of $31.8 million attributable to increased NGL margins and output at our Houston Central plant. During the year ended December 31, 2006, the HSC natural gas index price averaged $6.53 per MMBtu compared to $7.54 per MMBtu during the year ended December 31, 2005, a decrease of $1.01, or 13%. For a discussion of the commodity price environment, please read “— How We Evaluate Our Operations — Segment Gross Margin.”
 
Corporate and Other.  The corporate and other gain includes our commodity risk management activities of $1.4 million for the year ended December 31, 2006 compared to a gain of $0.4 million for the year ended December 31, 2005. The gain for the year ended December 31, 2006 is attributable to our commodity risk management activities and is comprised of (i) $12.1 million of net cash settlements received with respect to expired put contracts offset by (ii) $10.4 million of amortization expense related to purchased put derivatives and (iii) $0.3 million of unrealized losses related to the ineffective portion of our hedges. The gain for the year ended December 31, 2005 related to our commodity risk management activities commencing in July 2005 that were accounted for on a mark-to-market basis through October 24, 2005.
 
Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $32.5 million for the year ended December 31, 2006 compared to $18.5 million for the year ended December 31, 2005, an increase of $14.0 million, or 76%. This increase primarily relates to (i) our acquisition of certain Oklahoma assets in August 2005 of $11.3 million and (ii) increased field personnel, field utility, regulatory, pipeline lease, chemical, repair and maintenance expenses of $2.7 million in our Texas segment, partially as a result of acquiring approximately 200 miles of pipelines during 2006.
 
Depreciation and Amortization.  Depreciation and amortization totaled $32.0 million for the year ended December 31, 2006 compared with $17.1 million for the year ended December 31, 2005, an increase of $14.9 million, or 87%. This increase relates primarily to additional depreciation and amortization associated with acquisitions and capital expenditures made after December 31, 2005 and our acquisition of certain Oklahoma assets on August 1, 2005.
 
General and Administrative Expenses.  General and administrative expenses totaled $26.5 million for the year ended December 31, 2006 compared with $18.2 million for the year ended December 31, 2005, an increase of $8.3 million, or 46%. The increase primarily relates to (i) expenses associated with the operations of our Oklahoma segment acquired in August 2005 of $2.6 million, (ii) expenses associated with additional personnel, consultants and office space and compensation adjustments of $3.2 million (excluding those expenses associated with our Oklahoma segment), (iii) costs of Sarbanes-Oxley compliance and accounting fees of $0.9 million and (iv) non-cash compensation expense related to the amortization of the fair value of restricted units and unit options issued to employees and directors of $0.6 million. Additionally, we experienced an increase of $1.0 million related to expenses associated with acquisition initiatives that were not consummated.
 
Interest Expense.  Interest and other financing costs totaled $32.9 million for the year ended December 31, 2006 compared with $20.5 million for the year ended December 31, 2005. Interest expense related to our senior secured revolving credit facility totaled $8.8 million (net of $1.0 million of capitalized interest and settlements under our interest rate swaps) and $8.1 million for the years ended December 31, 2006 and 2005, respectively.


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Interest on our Senior Notes totaled $16.5 million for the year ended December 31, 2006. Interest on our unsecured term loan and our term loan facility totaled $3.1 million for the year ended December 31, 2006. Interest on our term loan facility totaled $6.6 million for the year ended December 31, 2005. Amortization of debt issue costs totaled $4.5 million and $5.8 million for the years ended December 31, 2006 and 2005, respectively. Amortization of debt issue costs for the year ended December 31, 2006 included a one-time charge of $1.7 million related to the reduction of the commitment under our senior secured revolving credit facility from $350 million to $200 million and a one-time charge of $0.6 million related to the early termination of the unsecured term loan. Amortization of debt issue costs for the year ended December 31, 2005 included one-time charges of $1.6 million related to the early termination of credit facilities in existence prior to the senior secured revolving credit facility. Interest expense increased primarily as a result of increased borrowings under our credit agreements as a result of our acquisition of our Oklahoma segment on August 1, 2005 and the issuance of our Senior Notes in February 2006. Average borrowings under these credit arrangements were $373.2 million and $227.5 million with average interest rates of 8.3% and 7.6% for the years ended December 31, 2006 and 2005, respectively. Please read “— Liquidity and Capital Resources — Description of Our Indebtedness” for a detailed discussion of our senior secured revolving credit facility and our Senior Notes.
 
General Trends and Outlook
 
Our segment gross margins are influenced by the price of natural gas and by drilling activity in our operating regions. In our Oklahoma segment, increases in natural gas prices generally have a positive impact on our segment gross margins and, conversely, a reduction in natural gas prices negatively impacts our segment gross margins. Increases in natural gas prices generally have a negative impact on our Texas segment gross margins and, conversely, a reduction in natural gas prices positively impacts our Texas segment gross margins. On average, natural gas prices for the last half of 2007 trended upward as compared to natural gas prices for 2006. The profitability of our Rocky Mountains segment is not significantly affected by commodity prices because substantially all of its contractual arrangements are fixed-fee arrangements.
 
Volumes of natural gas on our pipelines also impact our segment gross margins. Increases in volumes gathered or transported positively impact our segment gross margins and conversely, reductions in volumes gathered or transported negatively impact our segment gross margins. Higher natural gas prices typically encourage drilling activity in our operating regions. On average, the volume of natural gas on our pipelines increased in 2007 as compared to 2006. We believe that natural gas prices will continue to fluctuate over the next twelve months but will remain at levels sufficient to support continued drilling activity.
 
Our Oklahoma and Texas segment gross margins are also influenced by the price of NGLs and the content of NGLs contained in natural gas delivered to our plants or that we deliver to third-party plants where we process natural gas. Increases in NGL prices have a positive impact on these segment gross margins and, conversely, a reduction in NGL prices negatively impacts these segment gross margins for each of our operating segments. On average, NGL prices for 2007 trended upward as compared to NGL prices for 2006. Average NGL prices for 2006 were higher than the full-year average price in 2005. We believe that NGL prices will continue to fluctuate in 2008, but at levels generally consistent with current levels. The content of NGLs in natural gas delivered to our plants or that we deliver to third-party plants where we process natural gas also impacts these gross margins. Increases in the content of NGLs in this natural gas positively impacts our Oklahoma and Texas segment gross margins if the price of NGLs exceeds the cost of the natural gas required to extract such NGLs. Conversely, reductions in the NGL content of this natural gas negatively impact our segment gross margins under such circumstances.
 
In addition to operating and maintenance expenses, general and administrative expenses and maintenance capital expenditures, our distributable cash flow is impacted by the interest expense we pay on our indebtedness. Currently, interest rates on substantially all of our borrowings outstanding under our senior secured revolving credit facility effectively are fixed as a result of interest rate hedges. Our borrowings in excess of currently hedged amounts bear interest at a rate that fluctuates based on reserve-adjusted interbank offered market rates. Increases in floating interest rates have a negative impact on our distributable cash flow and, conversely, decreases in floating interest rates have a positive impact on distributable cash flow. Interest rates for 2007 and 2008 have trended downward.


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Impact of Inflation
 
Inflation in the United States has been relatively low in recent years in the economy as a whole. The midstream natural gas industry has experienced an increase in labor and materials costs during the year, although these increases did not have a material impact on our results of operations for the periods presented. Although the impact of inflation has not been significant in recent years, it is still a factor in the United States economy in general and specifically in the midstream natural gas industry and may further increase the cost to acquire or replace property, plant and equipment and may further increase the cost of labor and supplies and capital available to us. To the extent permitted by competition, regulation and our existing agreements, we may pass along increased costs to our customers in the form of higher fees.
 
Liquidity and Capital Resources
 
Cash generated from operations, borrowings under our senior secured revolving credit facility and funds from equity and debt offerings are our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.
 
Off-Balance Sheet Arrangements.  We had no off-balance sheet arrangements as of December 31, 2007.
 
Capital Requirements.  The natural gas gathering, transmission, and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:
 
  •  maintenance capital expenditures, which are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and
 
  •  expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems, transmission capacity or processing plants and to construct or acquire new pipelines or processing plants.
 
Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider a variety of assets for potential acquisitions. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “— Our Long-Term Growth Strategy — Acquisition Analysis.”
 
During the year ended December 31, 2007, our capital expenditures totaled $893.4 million, consisting of $9.1 million of maintenance capital and $884.3 million of expansion capital. We funded our capital expenditures with funds from operations, borrowings under our senior secured revolving credit facility and the issuance of additional equity. Additional expansion capital expenditures were related to the acquisition and construction of small pipeline systems, purchasing compressors and constructing well interconnects to attach volumes in new areas. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured revolving credit facility and the issuance of additional equity or debt as appropriate given market conditions. Based on our current scope of operations, we anticipate incurring approximately $11.0 million to $13.0 million of maintenance capital expenditures over the next 12 months.


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Contractual Cash Obligations.  A summary of our contractual cash obligations as of December 31, 2007, is as follows:
 
                                         
    Payment Due by Period  
    Total
                      More than 5
 
Type of Obligation
  Obligation     Within 1 Year     2-3 Years     4-5 Years     years  
    (In thousands)  
 
Long-term debt
  $ 630,000     $     $     $     $ 630,000  
Interest(1)
    316,806       46,095       92,191       88,611       89,909  
Gathering and transportation firm commitments
    161,222       20,630       35,774       32,780       72,038  
Operating leases
    7,260       3,322       2,906       1,032        
                                         
Total contractual cash obligations(1)
  $ 1,115,288     $ 70,047     $ 130,871     $ 122,423     $ 791,947  
                                         
 
 
(1) These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2007, the fair value of our interest rate swap contracts, which expire between July 2010 and October 2012, totaled $4.1 million.
 
In addition to our contractual obligations noted in the table above, we have both fixed and variable quantity contracts to purchase natural gas, which were executed in connection with our natural gas marketing activities. As of December 31, 2007, we had fixed contractual commitments to purchase 1,296,500 MMBtu of natural gas in January 2008. All of these contracts were based on index-related prices. Using these index-related prices at December 31, 2007, we had total commitments to purchase $8.9 million of natural gas under such agreements. Our contracts to purchase variable quantities of natural gas at index-related prices range from one month to the life of the dedicated production. During December 2007, we purchased 9,410,259 MMBtu of natural gas under such contracts.
 
For a discussion of our real property leases, please read Item 1, “Business — Office Facilities.”
 
Cash Flows.
 
The following summarizes our cash flows for each of the three years ended December 31, 2007, as reported in the historical consolidated statements of cash flows found in Item 8 of this Annual Report.
 
                         
    Year Ended December 31,  
    2007     2006     2005  
    (In thousands)  
 
Net cash provided by operating activities
  $ 128,218     $ 91,679     $ 280  
Net cash used in investing activities
    (727,052 )     (70,291 )     (491,708 )
Net cash provided by (used in) financing activities
    632,015       (7,201 )     509,710  
                         
Net increase in cash and cash equivalents
    33,181       14,187       18,282  
Cash and cash equivalents at beginning of year
    39,484       25,297       7,015  
                         
Cash and cash equivalents at end of year
  $ 72,665     $ 39,484     $ 25,297  
                         


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Operating Activities:
 
                         
    Year Ended December 31,  
    2007     2006     2005  
    (In thousands)  
 
Net income
  $ 63,175     $ 65,114     $ 30,352  
Depreciation and amortization
    41,633       36,455       22,775  
Equity in earnings from unconsolidated affiliates
    (2,850 )     (1,297 )     (927 )
Distributions from unconsolidated affiliates
    3,706              
Equity compensation and other
    4,318       2,086       1,309  
Cash used in working capital
    18,236       (10,679 )     (53,229 )
                         
Net cash provided by operating activities
  $ 128,218     $ 91,679     $ 280  
                         
 
The overall increase of $36.5 million in operating cash flow for the year ended December 31, 2007 compared to the year ended December 31, 2006 was primarily the result of (i) increase in distributions from Webb Duval and Southern Dome, our unconsolidated affiliates, of $3.7 million, (ii) an increase in non-cash items of $5.9 million and (iii) increases in working capital components (exclusive of cash and cash equivalents) of $28.8 million offset by (iv) a decrease in net income of $1.9 million. The increase in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of decreases in accounts receivable and prepaid items of $52.9 million offset by an increase in risk management assets of $1.3 million and increases in accounts payable and accrued liabilities of $80.4 million.
 
The overall increase of $91.4 million in operating cash flow for the year ended December 31, 2006 compared to the year ended December 31, 2005 was primarily the result of an increase in net income of $34.8 million, an increase in non-cash items of $14.1 million and an increase in the changes in working capital components (exclusive of cash and cash equivalents) of $42.5 million. This increase in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of increases in accounts receivable and prepaid items of $31.7 million and risk management assets of $19.6 million and a decrease in accounts payable and accrued liabilities of $8.8 million.
 
We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities for the next 12 months. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our senior secured revolving credit facility and Senior Notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our senior secured revolving credit facility and the issuance of additional equity and debt securities, as appropriate. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit ratings at the time.
 
Investing Activities.  Net cash used in investing activities was $727.1 million for the year ended December 31, 2007. Investing activities for 2007 included (i) $641.1 million of capital expenditures related to the Cantera and Cimmarron acquisitions, (ii) $84.3 million of capital expenditures related to bolt-on pipeline acquisitions, the expansion and modification of our Paden plant and progress payments for the purchase of compression and (iii) $1.7 million of investment in Bighorn after the closing of the acquisition in October 2007.
 
Net cash used in investing activities was $70.3 million for the year ended December 31, 2006. Investing activities for 2006 include costs primarily related to (i) $59.9 million of capital expenditures for several bolt-on pipeline acquisitions, costs related to the construction of an 11-mile pipeline to our Provident City system, progress payments for the purchase of compressor units, the installation of an additional amine treater and a modification of an existing amine treater at our Houston Central plant, the addition and installation of a refrigeration unit and condensate stabilizer at the Paden plant in Oklahoma, the construction of an 8-mile pipeline between two compressor stations in our Oklahoma area and the acquisition of rights-of-way and (ii) $10.4 million


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investment in Southern Dome, our unconsolidated affiliate, for the construction of a processing plant and residue pipelines that began operations in late April 2006.
 
Net cash used in investing activities was $491.7 million for the year ended December 31, 2005. Capital expenditures for 2005 include costs related to the acquisition of our Oklahoma segment and several small pipeline systems and the completion of well connections.
 
Financing Activities.  Net cash provided by financing activities totaled $632.0 million during the year ended December 31, 2007 and included (i) borrowings under our senior secured revolving credit facility of $538.0 million, (ii) issuance of additional Senior Notes of $125.8 million, (iii) proceeds from our private placements of common units of $157.1 million and Class E units of $177.9 million in October 2007 in connection with the Cantera acquisition, (iv) capital contributions of $10.0 million from our pre-IPO Investors to fulfill their G&A expense reimbursement obligations and (v) proceeds from the exercise of unit options of $1.8 million, offset by (a) repayments under our debt arrangements of $289.5 million, (b) distributions to our unitholders of $73.6 million, (c) deferred financing costs of $10.7 million and (d) equity offering costs of $4.8 million related to our private placements of equity during 2007.
 
Net cash used in financing activities totaled $7.7 million during the year ended December 31, 2006 and included (i) net proceeds from our follow-on public offering of common units in December 2006 of $161.8 million, (ii) net proceeds from our private placement of common units of $24.4 million in January 2006, (iii) capital contributions of $4.6 million from our pre-IPO investors and (iv) proceeds from the exercise of unit options of $0.4 million, offset by (a) net repayments under our debt arrangements of $144.9 million, (b) distributions to our unitholders of $47.0 million and (c) deferred financing costs of $7.0 million.
 
Net cash provided by financing activities totaled $509.7 million during the year ended December 31, 2005 and included (i) net borrowings under our credit facilities of $341.0 million, (ii) net proceeds from the private placement of common units and Class B units of $198.9 million in August 2005 and December 2005 and (iii) capital contributions of $4.2 million from our pre-IPO investors and from the exercise of unit options, offset by (a) distributions to our unitholders of $23.4 million, (b) deferred financing costs of $9.8 million and (c) $1.2 million of payments under short-term financing arrangements.
 
Cash Distributions and Reserves.  For a discussion of our cash distributions and reserves, please read Item 5 “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” of this Annual Report.
 
Description of Our Indebtedness
 
As of December 31, 2007 and 2006, our aggregate outstanding indebtedness totaled $630 million and $255 million, respectively.
 
Credit Ratings.  Moody’s Investors Service has assigned a Corporate Family Rating to us of B1 with a positive outlook, a B2 rating for our Senior Notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a positive outlook and a B+ rating for our Senior Notes.
 
Senior Secured Revolving Credit Facility.  Our senior secured revolving credit facility (the “Credit Facility”) is provided by Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders, and was established in August 2005. Our obligations under the Credit Facility are secured by first priority liens on substantially all of our assets and substantially all of the assets of our wholly owned subsidiaries (except for certain equity interests we acquired through our acquisitions of Cantera and Cimmarron), all of which are party to the Credit Facility as guarantors. Our less-than-wholly owned subsidiaries have not pledged their assets to secure the Credit Facility and do not guarantee obligations under the Credit Facility.
 
In January 2007, we modified the Credit Facility to, among others things, extend its maturity date to April 15, 2012, revise the interest rate provisions and the commitment fee provisions, increase the maximum ratio of our total debt to EBITDA (as defined under the Credit Facility) permitted under the Credit Facility and eliminate the following: (i) the limitation on our use of borrowings under the Credit Facility to make certain types of capital


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expenditures, (ii) the maximum consolidated fixed charge coverage ratio covenant and (iii) the maximum consolidated senior leverage ratio covenant.
 
On October 19, 2007, in connection with the Cantera acquisition, we further amended our Credit Facility to increase the aggregate borrowing capacity under the Credit Facility from $200 million to $550 million, extend the maturity date to October 18, 2012, revise the interest rate and commitment fee provisions, revise certain covenants to accommodate our obligations as managing member of each of Bighorn and Fort Union, and to accommodate previously existing obligations of each entity, provide for swing line borrowings in addition to committed borrowings, revise the minimum consolidated interest coverage ratio from 3.0:1 to 2.5:1, and increase the sublimit for the issuance of standby letters of credit from $25 million to $50 million.
 
Future borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The Credit Facility is available to be drawn on and repaid without restriction so long as we are in compliance with the terms of the Credit Facility, including certain financial covenants.
 
Annual interest under the Credit Facility is determined, at our election, by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable margin ranging from 1.25% to 2.50%, or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin ranging from 0.25% to 1.50%. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period. The effective average interest rate on borrowings under the Credit Facility for the years ended December 31, 2007, 2006 and 2005 was 6.9%, 7.4% and 6.15%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility for those periods, respectively, was 0.20%, 0.25% and 0.25%.
 
The Credit Facility contains various covenants that, subject to exceptions, limit our and subsidiary guarantors’ ability to grant liens; make loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the Credit Facility limits our and our subsidiary guarantors’ ability to incur additional indebtedness, subject to exceptions, including (i) purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.
 
The Credit Facility also contains financial covenants, which, among other things, require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios or conditions as follows:
 
  •  EBITDA to interest expense of not less than 2.5 to 1.0; and
 
  •  total debt to EBITDA of not more than 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).
 
Based on the total debt to EBITDA ratio calculated as of December 31, 2007 (utilizing trailing four quarters’ EBITDA as defined under the Credit Facility), we have approximately $270.0 million of unused capacity under the Credit Facility.
 
If an event of default exists under the Credit Facility, the lenders may accelerate the maturity of the obligations outstanding under the Credit Facility and exercise other rights and remedies. Each of the following would be an event of default:
 
  •  failure to pay any principal when due or any interest, fees or other amount within specified grace periods;
 
  •  failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to certain grace periods in some cases;
 
  •  default on the payment of any other indebtedness in excess of $5 million, or in the performance of any obligation or condition with respect to such indebtedness, beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;


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  •  bankruptcy or insolvency events involving us or our subsidiaries;
 
  •  if Bighorn or Fort Union is unable to make a quarterly distribution to its members, our inability to demonstrate compliance with financial covenants within a specified period;
 
  •  the entry of, and failure to pay, one or more adverse judgments in excess of $5 million upon which enforcement proceedings are brought or are not stayed pending appeal; and
 
  •  a change of control (as defined in the Credit Facility).
 
Our management believes that we are in compliance with the covenants under the Credit Facility as of December 31, 2007.
 
Senior Notes.  In February 2006, we issued $225 million in aggregate principal amount of our 81/8% senior notes due 2016 (the “Senior Notes”). In November 2007, we issued an additional $125 million in aggregate principal amount of our Senior Notes. The additional Senior Notes were offered under our effective shelf registration statement and constitute an additional issuance under the indenture governing the Senior Notes. We used the net proceeds, after deducting initial purchaser discounts and offering costs of $1.3 million, to reduce the balance outstanding under our Credit Facility.
 
The Senior Notes represent our senior unsecured obligations and rank equally in right of payment with all our other present and future senior indebtedness. The Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness, and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us, if any). The Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.
 
The Senior Notes are jointly and severally guaranteed by all of our wholly owned subsidiaries (other than Copano Energy Finance Corp., the co-issuer of the Senior Notes). The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our subsidiary guarantors (including under our Credit Facility) to the extent of the value of the assets securing that indebtedness, and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.
 
Before March 1, 2009, we may, at any time or from time to time, use net proceeds from a public or private equity offering to redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price of 108.125% of the principal amount of the Senior Notes, plus any accrued and unpaid interest, so long as at least 65% of the aggregate principal amount of the Senior Notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.
 
The Senior Notes are redeemable in whole or in part, at our option, at any time on or after March 1, 2011 and at the redemption prices in the table below, together with any accrued and unpaid interest to the date of redemption.
 
         
Year
  Percentage  
 
2011
    104.0625%  
2012
    102.7083%  
2013
    101.3542%  
2014 and thereafter
    100.0000%  
 
Prior to March 1, 2011, we may redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price together with any accrued and unpaid interest to the date of the redemption.
 
The indenture governing the Senior Notes includes covenants that limit our and our subsidiary guarantors’ ability to, among other things:
 
  •  sell assets;


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  •  pay distributions on, redeem or repurchase our units, or redeem or repurchase our subordinated debt;
 
  •  make investments;
 
  •  incur or guarantee additional indebtedness or issue preferred units;
 
  •  create or incur liens;
 
  •  enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
 
  •  consolidate, merge or transfer all or substantially all of our assets;
 
  •  engage in transactions with affiliates;
 
  •  create unrestricted subsidiaries; and
 
  •  enter into sale and leaseback transactions.
 
These covenants are subject to customary exceptions and qualifications. Additionally, if the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service and Standard & Poor’s Ratings Services, many of these covenants will terminate. Our management believes that we are in compliance with the covenants under the Senior Notes indenture as of December 31, 2007.
 
Recent Accounting Pronouncements
 
Accounting for Uncertainty in Income Taxes.  In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes-An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”, by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is “more likely than not” to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 will be effective as of the beginning of our 2007 fiscal year, with any cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. The provisions of FIN 48 became effective as of the beginning of our 2007 fiscal year and our adoption of FIN 48 did not have a material impact on our consolidated financial position.
 
Business Combinations.  In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (“SFAS No. 141(R)”). We have not completed our assessment of the impact, if any, from our adoption of SFAS No. 141(R). SFAS No. 141(R) is effective for fiscal years beginning after November 15, 2008.
 
Fair Value Measurements.  In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No. 133. The standard is effective for reporting periods beginning after November 15, 2007. We adopted this statement beginning January 1, 2008 and the adoption did not have material impact on our consolidated cash flows, results of operations or financial position.
 
Fair Value Option for Financial Assets and Financial Liabilities.  In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We adopted this statement beginning January 1, 2008, and the adoption did not have a material impact on our consolidated cash flows, results of operations or financial position. We have chosen not to measure items subject to SFAS No. 159 at fair value.
 
Non-Controlling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51. In December 2007, the FASB issued SFAS No. 160, “Non-Controlling Interests in Consolidated Financial Statements — an Amendment of ARB No. 51” (SFAS No. 160). We are currently evaluating the impact that


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SFAS No. 160 might have on our financial statements upon adoption. SFAS No. 160 is effective for fiscal years beginning after November 15, 2008.
 
Critical Accounting Policies and Estimates
 
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, please read Notes 2 and 3 to the Consolidated Financial Statements contained in Item 8 in this Annual Report.
 
Impairment of Long-Lived Assets.  In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.
 
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:
 
  •  changes in general economic conditions in regions in which our assets are located;
 
  •  the availability and prices of raw natural gas supply;
 
  •  improvements in exploration and production technology;
 
  •  our ability to negotiate favorable sales agreements;
 
  •  our dependence on certain significant customers, producers, gatherers, and transporters of natural gas; and
 
  •  competition from other midstream service providers, including major energy companies.
 
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
 
Investments in Unconsolidated Affiliates — Equity Method of Accounting.  Although we own a 62.5% partnership interest in Webb Duval, a majority interest in Southern Dome and a 51% member interest in Bighorn and we operate all the pipelines owned by these entities, we account for these investments using the equity method of accounting. For unconsolidated affiliates that we own a greater than 50% interest in, we use the equity method of accounting because the minority general partners or members have substantive participating rights with respect to the management of these entities. We also use the equity method of accounting with respect to our 37.04% member interest in Fort Union.
 
Revenue Recognition.  Our natural gas, NGL and crude oil revenue is recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing. Transportation, gathering, compression and processing-related revenues are recognized in the period when the service is provided.


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Forward-Looking Statements
 
This Annual Report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this Annual Report, including, but not limited to, those under “— Our Results of Operation” and “— Liquidity and Capital Resources” are forward-looking statements. Statements included in this Annual Report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include statements related to plans for growth of the business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:
 
  •  our ability to successfully integrate any acquired assets or operations;
 
  •  the volatility of prices and market demand for natural gas and NGLs;
 
  •  our ability to continue to obtain new sources of natural gas supply;
 
  •  the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;
 
  •  our ability to retain our key customers;
 
  •  general economic conditions;
 
  •  the effects of government regulations and policies; and
 
  •  other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.
 
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Annual Report, including without limitation in conjunction with the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report under Item 1A, “— Risk Factors.” All forward-looking statements included in this Annual Report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.
 
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk
 
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.
 
Commodity Price Risk.  NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is affected by prevailing commodity prices primarily as a result of two components of our business:


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(i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling volumes of natural gas at index-related prices. The following discussion describes our commodity price risks as of December 31, 2007.
 
A majority of the processing contracts in our Oklahoma segment are percentage-of-proceeds arrangements. Under these arrangements, we generally receive and process natural gas on behalf of producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase and revenues and gross margins decrease as natural gas and NGL prices decrease. Our Oklahoma segment also has fixed fee-contracts and percentage-of-index contracts.
 
Our Texas pipeline systems purchase natural gas for transportation and resale and also transport and provide other services on a fee-for-service basis. A significant portion of the margins we realize from purchasing and reselling the natural gas is based on a percentage of a stated index price. Accordingly, these margins decrease in periods of low natural gas prices and increase during periods of high natural gas prices. Although fees for natural gas that we transport on our pipeline systems for the accounts of others are primarily fixed, our Texas contracts also include a percentage-of-index component in a number of cases. A significant portion of the gas processed by our Texas segment is processed under keep-whole with fee arrangements. Under these arrangements, increases in NGL prices or decreases in natural gas prices generally have a positive impact on our gross margins and, conversely, a reduction in NGL prices or increases in natural gas prices generally negatively impact our gross margins. However, the ability of our Houston Central plant to operate in a conditioning mode allows us to reduce our Texas processing operations’ exposure to commodity prices. Please read Item 1, “Business — Our Operations — Texas — Houston Central Systems and Processing Plant” for a discussion of our Texas segment’s conditioning capability.
 
The profitability of our Rocky Mountains segment is not significantly affected by the level of commodity prices. Substantially all of our Rocky Mountains contractual arrangements as well as the contractual arrangements of Fort Union and Bighorn are fixed-fee arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. The revenue we earn as a result of these arrangements is directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues under these arrangements would be reduced.
 
In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $1.3 million to our total segment gross margin for the year ended December 31, 2007. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in approximately a $1.2 million decrease to our total segment gross margin, and vice versa, for the year ended December 31, 2007. These relationships are not necessarily linear. Although our sensitivity analysis takes into account our hedge portfolio, , it does not fully reflect the effects of our hedging program due to the prices received for natural gas and NGLs during the year ended December 31, 2007. If actual prices were to fall below the strike prices of our hedges, sensitivity to the change in commodity prices would be reduced. Additionally, if processing margins are negative, we can operate our Houston Central plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact to our total segment gross margin.
 
Although we seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations, from time to time, we experience imbalances between our natural gas purchases and sales. For example, a producer could fail to deliver or deliver in excess of contracted volumes, or a consumer could take more or less than contracted volumes. To the extent our purchases and sales of natural gas are not balanced, we face increased exposure to commodity prices with respect to the imbalance.


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Commodity Price Hedging Activities.  We seek to mitigate the price risk of natural gas and NGLs through the use of commodity derivative instruments. These activities are governed by our risk management policy, which, as amended in November 2007, allows our management to:
 
  •  purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on WTI crude oil to hedge natural gas liquids produced or condensate collected by us or an entity or asset to be acquired by us if a binding purchase and sale agreement has been executed (a “Pending Acquisition”);
 
  •  purchase put or call options, enter into collars (purchase of a put together with the sale of a call) or “call or put spreads” ((i) purchase of a call and a sale of a call at a higher strike price or (ii) purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps on natural gas at Henry Hub, HSC or other highly liquid points relevant to our operations or a Pending Acquisition;
 
  •  purchase put options, enter into collars or “put spreads” (purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps on NGLs to which we, or a Pending Acquisition, has direct price exposure, priced at Mt. Belvieu or Conway; and
 
  •  purchase put options and collars and/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for any processing plant relevant to our operations or a Pending Acquisition.
 
Our policy also limits the maturity and notional amounts of our derivatives transactions and requires that:
 
  •  Maturities with respect to the purchase of any crude oil, natural gas, NGLs, fractionation spread or processing margin spread hedge instruments must be limited to five years from the date of the transaction;
 
  •  Through December 31, 2008, notional volume must not exceed the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or NGL put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or NGL spread options permitted by the policy;
 
  •  After December 31, 2008, notional volume must not exceed 80% of the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or NGLs put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or NGL spread options; and
 
  •  The aggregate volumetric exposure associated with swaps, collars and written calls relating to any product must not exceed 50% of the aggregate hedged position with respect to such product.
 
Our policy of limiting swaps as a percentage of our overall hedge positions is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.
 
Our risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (“NYMEX”) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.
 
We will seek, whenever possible, to enter into hedge transactions that meet the requirements for effective hedges as outlined in SFAS No. 133.
 
Oklahoma Segment.  Natural gas for our Oklahoma segment is hedged using the CenterPoint East index, the principal index used to price the underlying commodity. With the exception of condensate, NGLs are contractually priced using the Conway index but since there is an extremely limited forward market for Conway, we use


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Mt. Belvieu hedge instruments instead. While this creates the potential for basis risk, statistical analysis reveals that the two indices have been historically highly correlated.
 
Texas Segment.  With the exception of condensate and a portion of our natural gasoline production, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. We use natural gas call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central plant. The call spread options are based on the HSC index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas segment because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central plant to switch between full recovery and conditioning mode.
 
Rocky Mountains Segment.  Since the profitability of our Rocky Mountains segment is not significantly affected by the level of commodity prices, this segment has no outstanding transactions to hedge commodity price risk.
 
The following table summarizes our commodity hedge portfolio as of December 31, 2007 (all hedges are settled monthly):
 
Purchased CenterPoint East Natural Gas Puts
 
                         
    Put Strike
  Put Volumes
   
    (Per MMBtu)   (MMBtu/d)   Fair Value
 
2008
  $ 7.75       5,000     $ 2,080,000  
2009
  $ 6.95       5,000     $ 1,205,000  
 
Purchased HSC Index Natural Gas Call Spreads
 
                                 
    Call Strike
             
    (Per MMBtu)     Call Volumes
       
    Bought     Sold     (MMBtu/d)     Fair Value  
 
2008
  $ 8.15     $ 10.00       9,400     $ 1,172,000  
2009
  $ 7.75     $ 10.00       8,000     $ 2,224,000  
2010
  $ 7.35     $ 10.00       7,100     $ 2,441,000  
2011
  $ 6.95     $ 10.00       7,100     $ 2,839,000  
 
Purchased Purity Ethane Puts and Entered into Swaps as Listed Below:
 
                                                 
    Put     Swap  
    Strike
    Volumes
          Price
    Volumes
       
    (per gallon)     (Bbls/d)     Fair Value     (per gallon)     (Bbls/d)     Fair Value  
 
2008
  $ 0.5700       607     $     $ 0.5650       607     $ (4,674,000 )
2008
  $ 0.6250       2,900     $ 1,000     $ 0.6525       1,300     $ (8,302,000 )
2009
  $ 0.5900       2,200     $ 8,000     $ 0.6025       1,100     $ (6,536,000 )
2010
  $ 0.5550       1,600     $ 9,000     $ 0.5700       500     $ (2,851,000 )
2011
  $ 0.5300       1,700     $ 10,000     $ 0.5450       500     $ (2,866,000 )


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Purchased TET Propane Puts and Entered into Swaps as Listed Below:
 
                                                 
    Put     Swap  
    Strike
    Volumes
          Price
    Volumes
       
    (per gallon)     (Bbls/d)     Fair Value     (per gallon)     (Bbls/d)     Fair Value  
 
2008
  $ 0.8360       2,594     $ 1,000     $ 0.8700       745     $ (7,453,000 )
2008
  $ 0.8975       1,100     $ 2,000                          
2008
  $ 1.0500       396     $ 9,000     $           $  
2009
  $ 0.8725       2,200     $ 60,000                          
2009
  $ 0.9650       1,000     $ 81,000     $ 1.0275       1,000     $ (6,184,000 )
2010
  $ 0.8500       1,100     $ 65,000                          
2010
  $ 0.9460       700     $ 107,000     $ 0.9925       700     $ (4,106,000 )
2011
  $ 0.8265       1,100     $ 83,000                          
2011
  $ 0.9340       700     $ 139,000     $ 0.9750       700     $ (4,041,000 )
 
Purchased Non-TET Isobutane Puts and Entered into Swaps as Listed Below:
 
                                                 
    Put     Swap  
    Strike
    Volumes
          Price
    Volumes
       
    (per gallon)     (Bbls/d)     Fair Value     (per gallon)     (Bbls/d)     Fair Value  
 
2008
  $ 0.9900       622     $     $ 1.0450       92     $ (1,100,000 )
2008
  $ 1.0900       250     $                          
2009
  $ 1.0600       450     $ 10,000                          
2009
  $ 1.1600       100     $ 6,000     $ 1.2425       100     $ (733,000 )
2010
  $ 1.0350       300     $ 14,000                          
2010
  $ 1.1145       100     $ 10,000     $ 1.2025       100     $ (699,000 )
2011
  $ 1.0205       300     $ 20,000                          
2011
  $ 1.1100       100     $ 14,000     $ 1.1800       100     $ (691,000 )
 
Purchased Non-TET Normal-Butane Puts and Entered into Swaps as Listed Below:
 
                                                 
    Put     Swap  
    Strike
    Volumes
          Price
    Volumes
       
    (per gallon)     (Bbls/d)     Fair Value     (per gallon)     (Bbls/d)     Fair Value  
 
2008
  $ 0.9875       810     $     $ 1.0400       271     $ (3,112,000 )
2008
  $ 1.0800       300     $                          
2009
  $ 1.0525       700     $ 3,000                          
2009
  $ 1.1400       400     $ 6,000     $ 1.2275       400     $ (2,752,000 )
2010
  $ 1.0300       300     $ 3,000                          
2010
  $ 1.1000       200     $ 5,000     $ 1.1850       200     $ (1,313,000 )
2011
  $ 1.0205       300     $ 4,000                          
2011
  $ 1.0850       200     $ 6,000     $ 1.1700       200     $ (1,280,000 )
 
Purchased Non-TET Natural Gasoline Puts and Entered into Swaps
 
                                                 
    Put     Swap  
    Strike
    Volumes
          Price
    Volumes
       
    (per gallon)     (Bbls/d)     Fair Value     (per gallon)     (Bbls/d)     Fair Value  
 
2008
  $ 1.4850       300     $ 4,000     $ 1.5850       300     $ (2,170,000 )
2009
  $ 1.4400       200     $ 18,000     $ 1.5400       200     $ (1,219,000 )
2010
  $ 1.4080       300     $ 42,000     $           $  
2011
  $ 1.4100       300     $ 56,000     $           $  


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Purchased WTI Crude Oil Puts as Listed Below:
 
                         
    Put Strike
    Put Volumes
       
    (per barrel)     (Bbls/d)     Fair Value  
 
2008
  $ 55.00       1,000     $ 6,000  
2008
  $ 60.00       700     $ 13,000  
2009
  $ 55.00       1,000     $ 89,000  
2009
  $ 60.00       500     $ 101,000  
2010
  $ 55.00       1,000     $ 214,000  
2010
  $ 60.00       400     $ 166,000  
2011
  $ 55.00       1,000     $ 317,000  
2011
  $ 60.00       400     $ 225,000  
 
In January 2008, we purchased puts for ethane, propane, iso-butane, normal butane and West Texas Intermediate crude oil at strike price reflecting current market conditions, and divested previously acquired put options on these products at lower strike prices. These transactions were conducted through two investment grade counterparties in accordance with our risk management policy and were designated as cash flow hedges to mitigate the impact of increases in NGL prices. Our net costs for these transactions were approximately $15.6 million.
 
Interest Rates.  Our interest rate exposure results from variable rate borrowings under our debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. These activities are governed by our risk management policy, which limits the maturity and notional amounts of our interest rate swaps as well as restricts counterparties to certain lenders under our Credit Facility.
 
As of December 31, 2007, we were exposed to changes in interest rates as a result of the indebtedness outstanding under our Credit Facility of $280 million, of which $160 million was hedged with interest rate swaps to convert our floating interest rate to a fixed rate of 5.965%. Our Credit Facility had an average floating interest rate of 6.05% as of December 31, 2007 and a 1% increase in interest rates on the amount of debt in excess of the $160 million that was hedged would result in an increase in interest expense and a corresponding decrease in net income of approximately $1.2 million annually.
 
In January 2008, we entered into two new interest rate swap agreements with a notional amount of $50 million under which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the Credit Facility for fixed rate interest. Under these agreements, we pay the counterparty the fixed interest rate of approximately 3.23% monthly and receive back from the counterparty a variable interest rate based on three-month LIBOR rates. These interest rate swaps cover the period from February 2008 through October 2012 and the settlement amounts will be recognized as either an increase or decrease in interest expense.
 
Risk Management Oversight.  Our Risk Management Committee is responsible for our compliance with our risk management policy and is comprised of our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, General Counsel and the President of any operating subsidiary. The Audit Committee of our Board of Directors monitors the implementation of our policy and we have engaged an independent firm to provide additional oversight.
 
Credit Risk.  We are diligent in attempting to ensure that we provide credit to only credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the year ended December 31, 2007, Enterprise Products Operating, L.P. (20%), ONEOK Energy Services (16%), ONEOK Hydrocarbons, L.P. (14%), Kinder Morgan Texas Pipeline, L.P. (10%), High Sierra Crude Oil and Marketing, LLC dba Interstate Petroleum Corporation (6%) and Enogex, Inc. (5%) collectively accounted for approximately 71% of our revenue. As of December 31, 2007, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services, or we had letters of credit from investment grade financial institutions supporting our credit exposure.


77


 

Item 8.   Financial Statements and Supplementary Data
 
The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-54 of this Annual Report and are incorporated herein by reference.
 
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.  Controls and Procedures
 
Management’s Evaluation of Disclosure Controls and Procedures
 
We carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report. Disclosure controls and procedures are defined as controls and other procedures that are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
 
Management’s Annual Report on Internal Control over Financial Reporting
 
Our management, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) of the Exchange Act. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)) as of the end of the period covered by this report. We based our evaluation on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in the publication entitled, “Internal Control — Integrated Framework” (the “COSO Framework”).
 
Based on our evaluation and the COSO Framework, we believe that, as of December 31, 2007, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Deloitte & Touche LLP, our independent registered public accounting firm, has issued a report on our internal control over financial reporting, which is included in “Report of Independent Registered Public Accounting Firm” below.
 
Changes in Internal Controls Over Financial Reporting
 
Under the direction of our Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and concluded that (i) our disclosure controls and procedures were effective as of December 31, 2007, and (ii) no change in our internal control over financial reporting occurred during the quarter ended December 31, 2007, that has materially affected, or is reasonably likely to materially affect such internal control over financial reporting.


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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
AS OF DECEMBER 31, 2007
 
The management of Copano Energy, L.L.C. and its consolidated subsidiaries, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)) as of the end of the period covered by this report. The Company based its evaluation on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in the publication entitled, “Internal Control — Integrated Framework” (the “COSO Framework”). Our assessment of internal controls over financial reporting included design effectiveness and operating effectiveness of internal control over financial reporting, as well as the safeguarding of our assets.
 
Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. A system of internal control may become inadequate over time because of changes in conditions or deterioration in the degree of compliance with the policies or procedures. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
 
In conducting our evaluation of the effectiveness of our internal control over financial reporting, we excluded the acquisitions of Cimmarron in May 2007 and Cantera in October 2007 due to their size and complexity. The Cimmarron acquisition constituted approximately 9% of total assets, 6% of total revenues, and 1% of total segment gross margin for the year ended December 31, 2007. The Cantera acquisition constituted 40% of total assets, and 1% each of total revenues and total segment gross margin for the year ended December 31, 2007. Such exclusion was in accordance with Securities and Exchange Commission guidance that an assessment of recently acquired business may be omitted in management’s report on internal controls over financial reporting, providing the acquisition took place within twelve months of management’s evaluation.
 
We are in the process of evaluating the internal control structure over the operations of Cimmarron and Cantera. We expect this effort will continue into future fiscal quarters of 2008 due to the magnitude of the business.
 
Based on our assessment, we believe that, as of December 31, 2007, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO Framework.
 
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 29, 2008.
 
     
/s/  John R. Eckel, Jr.

John R. Eckel, Jr.
Chairman of the Board of Directors and Chief Executive Officer
 
/s/  Matthew J. Assiff

Matthew J. Assiff
Senior Vice President and Chief Financial Officer


79


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Unitholders of Copano Energy, L.L.C and Subsidiaries:
Houston, Texas
 
We have audited the internal control over financial reporting of Copano Energy, L.L.C. and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Cimmarron Gathering, LP (“Cimmarron”) and Cantera Natural Gas, LLC (“Cantera”), which were acquired on May 1, 2007 and October 1, 2007, respectively, and whose financial statements constitute 14% and 78% of net assets, 9% and 40% of total assets, 10% and 9% of revenues, and 3% and 1% of net income of the consolidated financial statement amounts, respectively, as of and for the year ended December 31, 2007. Accordingly, our audit did not include the internal control over financial reporting at Cimmarron and Cantera. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.


80


 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007 of the Company and our report dated February 29, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph on the required adoption of new accounting principles related to the accounting for conditional asset retirement obligations, share-based payments and purchases and sales of inventory with the same counterparty.
 
/s/  Deloitte & Touche LLP
Houston, Texas
February 29, 2008
 
Item 9B.  Other Information
 
None.


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PART III
 
Item 10.   Directors and Executive Officers of the Registrant
 
The information required by Item 10 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2008 Annual Meeting of Unitholders set forth under the caption “Proposal One — Election of Directors,” “The Board of Directors and its Committees” and “Executive Officers” to be filed with the SEC not later than 120 days after the close of the fiscal year.
 
Item 11.   Executive Compensation
 
The information required by Item 11, including information concerning grants under our equity compensation plan for directors and employees, is incorporated herein by reference to the applicable information in our Proxy Statement for our 2008 Annual Meeting of Unitholders set forth under the captions “The Board of Directors and its Committees — Director Compensation,” “The Board of Directors and its Committees — Compensation Committee Interlocks and Insider Participation,” “Compensation Disclosure and Analysis,” “Executive Compensation,” “Report of the Compensation Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance” to be filed with the SEC not later than 120 days after the close of the fiscal year.
 
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
 
The information required by Item 12, including information concerning securities authorized for issuance under our equity compensation plan for directors and employees, is incorporated herein by reference to our Proxy Statement for our 2008 Annual Meeting of Unitholders set forth under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation” to be filed with the SEC not later than 120 days after the close of the fiscal year.
 
Item 13.   Certain Relationships and Related Parties
 
The information required by Item 13 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2008 Annual Meeting of Unitholders set forth under the caption “Certain Relationships and Related Transactions” to be filed with the SEC not later than 120 days after the close of the fiscal year.
 
Item 14.   Principal Accountant Fees and Services
 
The information required by Item 14 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2008 Annual Meeting of Unitholders set forth under the caption “Proposal Two — Ratification of Independent Public Accountants” to be filed with the SEC not later than 120 days after the close of the fiscal year.


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PART IV
 
Item 15.   Exhibits and Financial Statement Schedules
 
(a)(1) and (2) Financial Statements
 
The consolidated financial statements of Copano Energy, L.L.C. and the financial statements of Bighorn Gas Gathering, L.L.C. are listed on the Index to Financial Statements to this Annual Report beginning on page F-1.
 
(a)(3) Exhibits
 
The following documents are filed as a part of this Annual Report or incorporated by reference.
 
         
Number
 
Description
 
  2 .1   Purchase Agreement dated as of August 31, 2007 among Copano Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and Cantera Resources Holdings LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed October 25, 2007).
  2 .2   Contribution Agreement dated as of April 5, 2007 by and among Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, L.L.C. and Copano Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed April 11, 2007).
  3 .1   Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
  3 .2   Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
  3 .3   Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed April 30, 2007).
  3 .4   Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed May 4, 2007).
  3 .5   Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. dated October 19, 2007 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed October 25, 2007).
  3 .6   Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C., dated October 19, 2007 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed October 25, 2007).
  4 .1   Indenture dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
  4 .2   Rule 144A Global Note representing $224,500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed February 8, 2006).
  4 .3   Regulation S Global Note representing $500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed February 8, 2006).
  4 .4   Registration Rights Agreement dated as of May 1, 2007, by and among Copano Energy, L.L.C. and Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, LLC (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 4, 2007).
  4 .5   Registration Rights Agreement by and between Copano Energy, L.L.C. and Cantera Resources Holdings LLC, dated October 19, 2007 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed October 25, 2007).
  4 .6   Registration Rights Agreement by and among Copano Energy, L.L.C. and the Purchasers, dated October 19, 2007 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed October 25, 2007).
  10 .1   Form of Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Amendment No. 3 to Registration Statement on Form S-1/A filed October 26, 2004).
  10 .2   First Amendment to Copano Energy, L.L.C. Long-Term Incentive Plan, dated October 27, 2005 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed November 2, 2005).


83


 

         
Number
 
Description
 
  10 .3   Second Amendment to Copano Energy, L.L.C. Long-Term Incentive Plan, dated May 25, 2006 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed May 30, 2006).
  10 .4   Administrative and Operating Services Agreement dated November 15, 2004, among Copano/Operations, Inc. and Copano Energy, L.L.C., and the Copano Operating Subsidiaries listed therein (incorporated by reference to Exhibit 3.4 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).
  10 .5   First Amendment to Administrative and Operating Services Agreement (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed November 9, 2007).
  10 .6   Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated April 9, 2003 (incorporated by reference to Exhibit 10.8 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
  10 .7   First Amendment to Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated July 30, 2004 (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
  10 .8   Assignment and Assumption Agreement between Copano/Operations, Inc. and CPNO Services, L.P. effective January 1, 2005 with respect to Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, as amended (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
  10 .9   Second Amendment to Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the Copano Controlling Entities, effective March 1, 2005 (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
  10 .10   Employment Agreement between Copano/Operations, Inc. and James J. Gibson, III, dated as of October 1, 2004 (incorporated by reference to Exhibit 10.10 to Amendment No. 4 to Registration Statement on Form S-1/A filed November 2, 2004).
  10 .11   Assignment and Assumption Agreement between Copano/Operations, Inc. and CPNO Services, L.P. effective January 1, 2005 with respect to Employment Agreement between Copano/Operations, Inc. and James J. Gibson, III (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
  10 .12   First Amendment to Employment Agreement between CPNO Services, L.P. and James J. Gibson, III, effective March 1, 2005 (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
  10 .13   Employment Agreement between CPNO Services, L.P. and John A. Raber dated as of August 1, 2005 (incorporated by reference to Exhibit 10.32 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .14   Employment Agreement between ScissorTail Energy, L.L.C. and Bruce Roderick dated as of August 1, 2005 (incorporated by reference to Exhibit 10.33 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .15   Employment Agreement between ScissorTail Energy, L.L.C. and Sharon Robinson dated as of August 1, 2005 (incorporated by reference to Exhibit 10.34 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .16   Employment Agreement between ScissorTail Energy, L.L.C. and Thomas Coleman dated as of August 1, 2005 (incorporated by reference to Exhibit 10.35 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .17   Employment Agreement between ScissorTail Energy, L.L.C. and Lee E. Fiegener dated as of August 1, 2005 (incorporated by reference to Exhibit 10.36 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .18   2004 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed December 15, 2004).
  10 .19   2004 Form of Unit Option Grant (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q filed December 21, 2004).
  10 .20   2005 Form of Restricted Unit Grant (Employees) (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-8 filed February 11, 2005).
  10 .21   2005 Form of Unit Option Grant (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8 filed February 11, 2005).
  10 .22   Form of Unit Option Grant (ScissorTail Energy, LLC Officers) (incorporated by reference to Exhibit 10.37 to Quarterly Report on Form 10-Q filed August 15, 2005).


84


 

         
Number
 
Description
 
  10 .23   Form of Restricted Unit Grant (ScissorTail Energy, LLC Officers) (incorporated by reference to Exhibit 10.38 to Quarterly Report on Form 10-Q filed August 15, 2005).
  10 .24   2006 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed May 30, 2006).
  10 .25   2006 Form of Unit Option Grant (Employees) (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed May 30, 2006).
  10 .26   2006 Form of Restricted Unit Grant (Employees) (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K filed May 30, 2006).
  10 .27   November 2006 Form of Grant of Restricted Units (Directors) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed November 20, 2006).
  10 .28   2007 Form of Phantom Unit Grant (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed June 18, 2007).
  10 .29   Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed March 2, 2005).
  10 .30   2007 Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed February 20, 2007).
  10 .31   2008 Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed February 27, 2008).
  10 .32   Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed November 2, 2005).
  10 .33   Copano Energy, L.L.C. Change in Control Severance Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed December 18, 2007).
  10 .34   Lease Agreement dated as of October 17, 2000, between Plow Realty Company of Texas and Texas Gas Plants, L.P. (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
  10 .35   Lease Agreement dated as of December 3, 1964, between The Plow Realty Company of Texas and Shell Oil Company (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
  10 .36   Lease Agreement dated as of January 1, 1944, between The Plow Realty Company of Texas and Shell Oil Company, Incorporated (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
  10 .37†   Amended and Restated Gas Processing Contract entered into as of February 1, 2006, between Kinder Morgan Texas Pipeline, L.P. and Copano Processing, L.P. (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed May 10, 2006).
  10 .38   Loan Agreement dated as of September 29, 2006, among Copano Energy, L.L.C., as the Borrower, Banc of America Bridge LLC, as Administrative Agent, and The Other Lenders Party Hereto and Banc of America Securities LLC, as Sole Lead Arranger and Sole Lead Manager (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed October 5, 2006).
  10 .39   Amended and Restated Credit Agreement dated as of January 12, 2007, among Copano Energy, L.L.C., as the Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association, as Co-Syndication Agents and The Other Lenders Party thereto and Banc of America Securities LLC, as Sole Lead Arranger and Sole Book Manager (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed January 19, 2007).
  10 .40*   First Amendment to Amended and Restated Credit Agreement, dated October 19, 2007.
  12 .1*   Statement of Computation of Ratios of Earnings to Fixed Changes.
  21 .1*   List of Subsidiaries.
  23 .1*   Consent of Deloitte & Touche LLP.
  23 .2*   Consent of Deloitte & Touche LLP.
  31 .1*   Sarbanes-Oxley Section 302 certification of John R. Eckel, Jr. (Chief Executive Officer) for Copano Energy, L.L.C.
  31 .2*   Sarbanes-Oxley Section 302 certification of Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.


85


 

         
Number
 
Description
 
  32 .1*   Sarbanes-Oxley Section 906 certification of John R. Eckel, Jr. (Chief Executive Officer) for Copano Energy, L.L.C.
  32 .2*   Sarbanes-Oxley Section 906 certification of Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.
 
 
* Filed herewith.
 
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
 
  (b)   Exhibits
 
See Item 15(a)(3) above.


86


 

SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 29th day of February 2008.
 
COPANO ENERGY, L.L.C.
 
  By: 
/s/  John R. Eckel, Jr.
John R. Eckel, Jr.
Chairman of the Board of Directors and
Chief Executive Officer
 
  By: 
/s/  Matthew J. Assiff
Matthew J. Assiff
Senior Vice President and Chief Financial Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities indicated.
 
             
Signature
 
Title
 
Date
 
/s/  John R. Eckel, Jr.

John R. Eckel, Jr.
  Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)   February 29, 2008
         
/s/  Matthew J. Assiff

Matthew J. Assiff
  Senior Vice President and Chief Financial Officer (Principal Financial Officer)   February 29, 2008
         
/s/  Lari Paradee

Lari Paradee
  Vice President and Controller (Principal Accounting Officer)   February 29, 2008
         
/s/  James G. Crump

James G. Crump
  Director   February 29, 2008
         
/s/  Ernie L. Danner

Ernie L. Danner
  Director   February 29, 2008
         
/s/  Michael L. Johnson

Michael L. Johnson
  Director   February 29, 2008
         
/s/  Scott A. Griffiths

Scott A. Griffiths
  Director   February 29, 2008
         
/s/  T. William Porter

T. William Porter
  Director   February 29, 2008
         
/s/  William L. Thacker

William L. Thacker
  Director   February 29, 2008


87


 

COPANO ENERGY, L.L.C.
 
INDEX TO FINANCIAL STATEMENTS