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The following is an excerpt from a 8-K SEC Filing, filed by COPANO ENERGY, L.L.C. on 1/20/2006.
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COPANO ENERGY, L.L.C. - 8-K - 20060120 - NOTES_TO_FINANCIAL_STATEMENT
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Transactions
      The unaudited pro forma consolidated financial statements reflect the following Transactions:
Refinancing:
  •  issuance of $225.0 million aggregate principal amount of the notes offered hereby (the “Notes”) and payment of $7.0 million for related debt issuance costs;
 
  •  refinancing a $170.0 million senior unsecured term loan and the write-off of related debt issuance costs of $2.3 million; and
 
  •  reduction of the outstanding balance under the Credit Agreement discussed below with the remaining proceeds from the Notes.
ScissorTail Transactions:
  •  $175.0 million aggregate placement of equity comprising 1,372,458 common units at a price of $28.78 per common unit for aggregate proceeds of $39.5 million and 4,830,758 Class B units at a price of $28.05 per Class B unit for aggregate proceeds of $135.5 million;
 
  •  payment of fees and expenses associated with the placement of equity estimated to be approximately $1.2 million;
 
  •  establishment of $350.0 million senior secured revolving credit facility (the “Credit Agreement”) with an initial draw of $232.0 million and payment of $5.1 million for related debt issuance costs;
 
  •  pay down of existing senior indebtedness of Copano with proceeds from the Credit Agreement;
 
  •  establishment of the $170.0 million senior unsecured term loan and payment of related expenses;
 
  •  purchase of cash management assets as a condition to closing the Credit Agreement and the senior unsecured term loan;
 
  •  acquisition of ScissorTail;
 
  •  issuance of restricted units to employees of ScissorTail; and
 
  •  payment of expenses and fees associated with the acquisition of ScissorTail.
IPO Transactions:
  •  the November 2004 public offering of 5,750,000 common units and the conversion or exchange of the pre-offering units into post-offering units;
 
  •  redemption of the redeemable preferred units; and
 
  •  pay down of senior indebtedness and certain other obligations with proceeds from the initial public offering.
Pro Forma Adjustments:
Balance Sheet
Refinancing
      (a)     Reflects proceeds from the issuance of $225.0 million aggregate principal amount of Notes and payment of $7.0 million for related debt issuance costs.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      (b)     Reflects the repayment of the $170.0 million senior unsecured term loan and the write off of related debt issuance costs of $2.3 million.
      (c)     Reflects a reduction of $48.0 million of existing senior indebtedness under the Credit Agreement with proceeds from the Notes.
Other
      (d)     The Class B units converted on a one-for-one basis into common units on October 27, 2005.
Statements of Operations
IPO Transactions
      (e)     Reflects the reversal of interest expense, accretion of the discount, write off of the discount and issuance costs and amortization of issuance costs of $17.0 million and $10.1 million for the year ended December 31, 2004 and for the twelve months ended September 30, 2005, respectively, related to the redeemable preferred units which were redeemed using proceeds from the initial public offering.
      (f)     Reflects a reduction in interest expense of $1.3 million and $0.2 million for the year ended December 31, 2004 and for the twelve months ended September 30, 2005, respectively, related to the repayment of existing senior indebtedness using proceeds from the initial public offering in November 2004.
      (g)     Excludes a nonrecurring charge of $0.7 million for the year ended December 31, 2004, related to the write-off of the remaining debt issuance costs associated with the existing senior indebtedness refinanced with proceeds from the ScissorTail Transactions. Such redemption is considered an early extinguishment of debt.
      (h)     Excludes the pro forma impact of general and administrative expense reimbursements that would have been made in accordance with the Copano limited liability company agreement. On a pro forma basis, such reimbursement amounts would have been approximately $0.8 million, $3.8 million and $4.7 million for the year ended December 31, 2004, for the nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively.
      (i)     Reflects the initial public offering of common units and the conversion or exchange of the pre-offering units into post-offering units as if the initial public offering occurred on January 1, 2004.
ScissorTail Transactions
      (j)     Reflects the equity placement of 1,372,458 common units and 4,830,758 Class B units.
      (k)     Reflects the reversal of $5.6 million, $10.7 million and $12.3 million for the year ended December 31, 2004, for the nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively, of interest expense and amortization of debt issuance costs related to the existing senior indebtedness repaid with proceeds from the Credit Agreement.
      (l)     Reflects $35.4 million, $27.0 million and $34.0 million for the year ended December 31, 2004, for the nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively, of interest expense and amortization of debt issuance costs related to the ScissorTail Transactions. An estimated rate for the senior unsecured term loan of 9.5%, 11% and 11% for the year ended December 31, 2004, for the nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively, was used to calculate this pro forma adjustment.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      (m)     Reflects the amortization of the intrinsic value of the restricted units issued to employees of ScissorTail at the closing of the acquisition of ScissorTail. Copano’s initial public offering price of $20.00 per common unit was used to establish the intrinsic value of these restricted units. Additionally, this pro forma adjustment reflects the dilutive effect of the restricted units issued to the ScissorTail employees at the closing of the ScissorTail acquisition.
      (n)     Reflects depreciation and amortization, based on the preliminary purchase price allocation of the new basis in property, plant and equipment and intangibles.
      (o)     Reflects reclassification of ScissorTail information to conform with Copano’s financial statement presentation.
      (p)     Reflects the reversal of $22.6 million of nonrecurring ScissorTail change of control expenses incurred in July 2005 as a result of our acquisition of ScissorTail. Please read “Certain Relationships and Related Transactions — Other.”
      (q)     The weighted average units outstanding used in the net income per unit calculation includes the common units, the subordinated units and the Class B units. Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated to holders of the common units, the subordinated units and the Class B units by the number of common units, subordinated units and Class B units expected to be outstanding at the closing of the Transactions. For purposes of this calculation, the total number of common, subordinated units and Class B units outstanding of 16,760,595 was assumed to have been outstanding since January 1, 2004. The “if-converted” method is used since the Class B units converted into common units on October 27, 2005 and the effect of conversion was dilutive.
Offering Transactions
      (r)     Reversal of interest expense and amortization of debt issuance costs related to the ScissorTail Transactions (see (l) above).
      (s)     Reflects $31.8 million, $24.0 million and $31.8 million for the year ended December 31, 2004, for the nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively, of interest expense and amortization of debt issuance costs as a result of the Refinancing. An interest rate change of 1 / 8 % for the notes offered hereby would change interest expense by $0.3 million, $0.2 million and $0.3 million for the year ended December 31, 2004, nine months ended September 30, 2005 and for the twelve months ended September 30, 2005, respectively.
      (t)     Excludes a nonrecurring charge of $3.9 million for the year ended December 31, 2004 related to the write-off of the debt issuance costs associated with the senior unsecured term loan to be refinanced with proceeds from the Refinancing. Such redemption is considered an early extinguishment of debt.
      Subordinated units will convert into common units on a one-for-one basis when the subordination period ends and at that time, common units will no longer be entitled to arrearages. The subordination period will end when Copano Energy, L.L.C. meets financial tests specified in the limited liability company agreement but generally cannot end before December 31, 2006.
      The Class B units represented a new class of equity securities that was entitled to a special quarterly distribution equal to 110% of the per unit distribution received by the common units, had no voting rights other than as required by law and was subordinated to the common units on dissolution and liquidation. On October 27, 2005, Copano’s unitholders approved the conversion of each of the Class B units into one common unit and the issuance of 4,830,758 additional common units upon such conversion.

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Our Contracts
      We seek to execute contracts with producers and shippers that provide us with positive gross margin in all natural gas and NGL pricing environments. Actual contract terms, however, are 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, our expansion in regions where some types of contracts are more common and other market factors.
Texas Gulf Coast Pipelines Contracts
      Our Texas Gulf Coast Pipelines segment purchases natural gas for transportation and resale and also transports and provides other services for natural gas that it does not purchase on a fee-for-service basis. For September 2005, we purchased 67% of the natural gas volumes delivered to our pipelines and transported 33% on a fee-for-service basis. These volumes exclude volumes associated with Webb Duval, substantially all of which are transported on a fee-for-service basis.
      Natural Gas Purchases. Generally, we purchase natural gas attached to our pipeline systems under discount-to -index arrangements. Under these arrangements, we generally purchase natural gas at either (1) a percentage discount to an index price, (2) an index price less a fixed amount or (3) a percentage discount to an index price less a fixed amount. We then gather, deliver and resell the natural gas under arrangements described below. For September 2005, volumes related to discount-to -index purchase arrangements accounted for 88% of total purchased volumes. The gross margins we realize under the arrangements described in clauses (1) and (3) 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. In many cases,

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our contracts for natural gas purchases allow us to charge producers fees for treating, compression, dehydration or services other than processing and conditioning.
      We also purchase natural gas under a limited number of intra-month, fixed-price arrangements used for balancing our portfolio for the month. Transactions under these arrangements are executed to support intra-month changes in operating conditions, including customer requirements, and not for purposes of speculation. For September 2005, volumes related to such fixed-price arrangements accounted for 12% of total purchased volumes.
      Fee-For-Service Transport. We generally transport natural gas on our pipeline systems under fixed fee arrangements pursuant to which our transportation fee income represents an agreed rate per unit of throughput. The revenue we earn from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these arrangements would be reduced. For September 2005, volumes related to fixed-fee arrangements accounted for 52% of total natural gas volumes that we transport on behalf of third-party shippers.
      We also derive some transportation fee income based upon percentage-of -index fee arrangements. Under this type of arrangement, the fee we receive for gathering or transporting the natural gas is based upon a percentage of an index price. The fee we realize under this type of arrangement decreases in periods of low natural gas prices and increases during periods of high natural gas prices. For September 2005, volumes related to percentage-of -index fee arrangements accounted for 2% of total transported volumes. For September 2005, volumes related to a combination of fixed-fee and percentage-of -index fee arrangements accounted for 46% of total transported volumes. In many cases, our contracts for natural gas transportation allow us to charge shippers fees for treating, compression, dehydration or services other than processing and conditioning.
      Natural Gas Sales. We sell natural gas to other natural gas pipelines, marketing affiliates of integrated oil companies or other midstream companies, utilities, power producers and end-users. We sell natural gas under index-related pricing terms with the exception of a limited number of intra-month fixed-price sales arrangements used for balancing our portfolio for the month. Transactions under these fixed-price arrangements are executed to support intra-month changes in operating conditions, including customer requirements, and not for purposes of speculation.
      Processing and Conditioning Services. With respect to natural gas requiring processing and conditioning services, our Texas Gulf Coast Pipelines segment contracts with our Texas Gulf Coast Processing segment to provide such services on the terms described below.
Texas Gulf Coast Processing Contracts
      With respect to services performed by our Texas Gulf Coast Processing operations, we contract under the following types of arrangements:
  •  Keep-Whole with Conditioning Fee Arrangements. Under keep-whole with conditioning fee arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under these types of arrangements, we also charge producers and third-party transporters a conditioning fee, at all times or in certain circumstances depending upon the terms of the particular contract. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs from the natural gas during processing or conditioning reduces the Btus of the natural gas. To replace these Btus, we must purchase natural gas at market prices for return to producers and transporters. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, we are generally able to reduce our commodity price exposure by conditioning rather than processing the natural gas, as described below.

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  For September 2005, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 82% of total plant volumes.
 
  •  Keep-Whole Without Conditioning Fee Arrangements. Under keep-whole without conditioning fee arrangements, we receive natural gas from the producer or third-party transporter, process the natural gas and sell the resulting NGLs to third parties at market prices. Like the arrangement described above, under these contracts we are required to replace the Btus reduced during processing or conditioning. These contracts are subject to all of the considerations described in “Keep-Whole With Conditioning Fee Arrangements” above, except that we do not charge the producer or transporter a conditioning fee. It is generally not our policy to enter into new keep-whole contracts without conditioning fee arrangements. For September 2005, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 16% of total plant volumes. Our Texas Gulf Coast Pipelines segment earned gross margins with respect to these volumes pursuant to other provisions of the applicable contract.
 
  •  Percentage-of -Proceeds Arrangements. Under percentage-of -proceeds arrangements, we generally receive and process natural gas on behalf of producers, sell or redeliver the resulting residue gas and sell the NGL volumes at index-related prices. We remit to producers an agreed upon index-related price for the natural gas, if not redelivered, and an agreed upon percentage of the NGL proceeds. Under these types of arrangements, our revenues and gross margins increase as NGL prices increase, and our revenues and gross margins decrease as NGL prices decrease. For September 2005, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 2% of total plant volumes.
 
  •  Fixed Fee, or Tolling, Arrangements. Under fixed fee arrangements, producers pay us a fixed fee to process their natural gas. These types of arrangements require us to pay the producer for the value of NGLs recovered and to redeliver the residue gas in exchange for a fixed fee. For September 2005, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for less than 1% of total plant volumes.
      We also provide processing and conditioning services under contracts that contain a combination of the arrangements described above. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter during periods where such margins are in excess of an agreed-upon amount.
      All of our processing agreements allow us to determine, in our sole discretion, whether we process or condition natural gas. We determine whether to process or condition the natural gas based upon the price of natural gas and various NGL products. When NGL extraction is uneconomic, NGLs are left in the natural gas stream to the maximum extent allowed by pipeline quality specifications, thus reducing the amount of fuel consumed by the processing plant and the loss in Btus resulting from the extraction of the NGLs. When we elect to condition natural gas, typically our natural gas fuel consumption volumes are reduced by approximately 79% and the Btu reduction associated with the extraction of NGLs is reduced by approximately 94% while our average barrels of NGLs extracted from natural gas is reduced by approximately 96%. For a detailed discussion of our processing and conditioning capabilities, please “Business — Our Operations — Texas Gulf Coast Processing Segment” contained elsewhere in this offering memorandum.
      NGL Product Sales. We use our Sheridan NGL Pipeline to transport NGLs to an interconnect with Enterprise Seminole Pipeline where we sell the NGLs at market prices. At the tailgate of the plant, we deliver and sell stabilized condensate to TEPPCO based on an index-related price.
      Our Commercial Relationship with Kinder Morgan Texas Pipeline. For the nine months ended September 30, 2005, approximately 83% of the natural gas volumes processed or conditioned at our Houston Central Processing Plant were delivered to the plant through the KMTP Laredo-to -Katy pipeline while the remaining 17% were delivered directly to the plant from our gathering systems. Of the volumes delivered to the plant from the KMTP Laredo-to -Katy pipeline, approximately 26% were delivered from gathering systems controlled by us, while 74% were delivered by KMTP from sources other than our gathering systems (the

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“KMTP Gas”). Of the total volume of NGLs extracted at the plant during this period, 40% originated from KMTP Gas, while 60% was attributable to gathering systems controlled by us, including our gathering systems connected directly to the plant. Under our contractual arrangement related 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. Because the extraction of NGLs from the natural gas stream during processing or conditioning reduces the Btus of the natural gas, our arrangement with KMTP requires us to purchase natural gas at market prices to replace the loss in Btus. Pursuant to an amendment to this contract with KMTP, effective January 1, 2004, we pay a fee to KMTP based on the NGL content of the KMTP Gas only during periods of favorable processing margins. In addition, the amendment provides that during periods of unfavorable processing margins, KMTP pays us a fixed fee plus an additional payment based on the index price of natural gas.
Mid-Continent Operations Contracts
      Natural Gas Supply and Transportation. We contract for supplies of natural gas from producers in our Mid-Continent region under several types of arrangements. Processing services, where applicable, are included in the purchase or transportation contract arrangement. Typically, the primary term of each contract varies significantly, ranging from one month to the life of the dedicated production. The specific terms of each natural gas supply contract are based upon a variety of factors including gas quality, pressure of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. These contracts may be structured as a percentage-of -proceeds, percentage-of -index, or fixed fee arrangements. For September 2005, calculated as a percentage of total volumes, 51% of our Mid-Continent volumes were under percentage-of -proceeds contracts, 32% were under percentage-of -index contracts and 17% were under fixed fee contracts.
      Percentage-of -Proceeds Arrangements. Under percentage-of -proceeds arrangements, our Mid-Continent Operations segment generally receives and processes natural gas on behalf of producers and sells the residue gas and NGL volumes at index-related prices. We remit to producers an agreed upon percentage of the residue gas and NGL proceeds. 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.
      Percentage-of -Index Arrangements. Our percentage-of -index contracts are divided into two subcategories — simple percentage-of -index contracts comprised 18% of our Mid-Continent Operations’ volumes for September 2005, while percentage-of -index with percentage-of -proceeds “switch” contracts comprised 14% of our Mid-Continent Operations’ volumes for September 2005. Under a percentage-of -index contract, we purchase and resell natural gas at an index-related price, deriving our gross margins from the difference. Under a percentage-of -index with a percentage-of -proceeds switch arrangement, we pay producers on either a percentage-of -proceeds or percentage-of -index basis, determined under these contracts on the basis most favorable to us.
      Fixed Fee Arrangements. Under substantially all fixed fee arrangements, producers pay us a fixed fee to gather their natural gas.
      Natural Gas Sales and NGL Sales. We sell natural gas in the Mid-Continent region under index-related pricing terms to marketing affiliates of integrated companies or other midstream companies, power producers and end-users. We sell natural gas under index-related pricing terms. Oneok Energy Services and Enogex are the largest purchasers of our natural gas. With respect to sales of NGLs in the Mid-Continent region, we sell the majority of our NGLs to Oneok Hydrocarbon Products Inc. or Enogex. All NGLs are sold under index-related pricing arrangements.
Our 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

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services. We also evaluate acquisitions in new geographic areas, including other areas of Texas and Oklahoma and in New Mexico and the Rocky Mountain 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 we will have a lower cost of equity capital than many of our competitors that are master limited partnerships, or MLPs, because, unlike in a traditional MLP structure, 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 debt and equity offerings. 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 asset in relation to our business strategy, expertise required to manage the asset, capital required to integrate and maintain the asset, 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 additive 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 over 30 acquisitions, including the acquisition of our Houston Central Processing Plant and our recent acquisition of ScissorTail Energy, LLC, and significant expansion and enhancement projects related to our assets. Our historical acquisitions were completed at different dates and with numerous 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.
      On August 1, 2005, we acquired ScissorTail for $499.1 million, and now refer to the business and properties of ScissorTail as our Mid-Continent Operations segment. The ScissorTail Acquisition nearly tripled our miles of natural gas gathering pipelines and increased processing capacity by 100,000 Mcf/d and is expected to provide significant additional throughput volumes and cash flow. Our nine months ended September 30, 2005 results of operation include the results of our Mid-Continent Operations from August 1, 2005 (the date we acquired ScissorTail) through September 30, 2005 and the Mid-Continent Operations generated approximately 25% of our total gross margin for the nine month period ended September 30, 2005.

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ScissorTail’s Historical Financial Performance
Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004
      Gross Margin. For the six months ended June 30, 2005, gross margin at ScissorTail increased $11.9 million from $20.1 million at June 30, 2004 to $32.0 million at June 30, 2005, an increase of 59.0%. The increase was primarily attributable to higher average throughput volumes during the six months ended June 30, 2005 compared to the six months ended June 30, 2004. During the first six months of 2005, throughput volume averaged 124,267 Mcf/d compared to 108,509 Mcf/d during the first six months of 2004, an increase of 15,758 Mcf/d, or 15.0%. Additional increases were attributable to higher average natural gas and NGL prices during the six months ended June 30, 2005 compared to the six months ended June 30, 2004, which resulted in an increase in margins associated with our index price purchases and transportation agreements. During the first six months of 2005, the six-month average of the first-of -month average of the Southern Star and Oneok natural gas index prices (as reported by Platt’s Inside FERC Gas Market Report) was $6.16 per MMBtu compared to $5.34 per MMBtu during the first six months of 2004. Additional increases in gross margin were primarily attributable to increased production in areas with relatively favorable contract terms, and decreased line losses of natural gas on ScissorTail’s pipeline systems and facilities.
      Operations and Maintenance Expenses. Operations and maintenance expenses increased $0.8 million from $5.5 million for the six months ended June 30, 2004 to $6.3 million for the six months ended June 30, 2005, an increase of 15.0%. On a unit basis, operations and maintenance expenses declined from $.280/ Mcf in the six months ended June 30, 2004 to $.277/ Mcf for the six months ended June 30, 2005. This was due primarily to the increase in expenses associated with higher production volumes.
      General and Administrative Expenses. General and administrative expenses remained unchanged at $1.7 million for both the period ended June 30, 2004 and the period ended June 30, 2005.
      Capital Expenditures. Capital expenditures were approximately $3.7 million in the first six months of 2005 versus $3.1 million in the first six months of 2004. This change is primarily attributable to timing differences with respect to otherwise comparable levels of capital expenditures.
Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
      Gross Margin. For the year ended December 31, 2004, gross margin at ScissorTail increased $26.3 million from $23.8 million at December 31, 2003 to $50.1 million at December 31, 2004, an increase of 111.0%. The increase was driven by the acquisition of certain assets from Duke Energy Field Services (“DEFS”) in June 2003 (the “DEFS Acquisition”) and strong volume growth on ScissorTail’s system. During 2004, both as a result of the DEFS Acquisition and volume growth on ScissorTail’s existing assets, throughput volume averaged 112,372 Mcf/d compared to 104,622 Mcf/d during 2003, an increase of 7,750 Mcf/d, or 7.4%. Additional increases in gross margin were attributable to higher average natural gas and NGL prices during the twelve months ended December 31, 2004 compared to the twelve months ended December 31, 2003, which resulted in an increase in margins associated with our index price purchases and transportation agreements. During 2004, the annual average of the first-of -month indices for Oneok Gas Transmission and Southern Star Central Gas Pipeline (previously the Williams Oklahoma index), as published in Platts Inside FERC Gas Market Report were $5.53 per MMBtu compared to $5.05 per MMBtu during 2003. Additional increases in gross margin were due to increased fee-based services, reductions in lost and unaccounted-for gas and more efficient operations.
      Operations and Maintenance Expenses. Operations and maintenance expenses, which consist primarily of field labor, compression, and maintenance and repair charges, increased from $7.9 million in 2003 to $11.3 million in 2004, or $3.4 million. This increase was primarily attributable to increased operating and maintenance costs as a result of the DEFS Acquisition which were partially offset by an improvement in compression and field labor efficiency.
      General and Administrative Expenses. General and administrative expenses increased from $3.0 million in 2003 to $3.8 million in 2004. This increase is primarily related to an increase in incentive plan payments

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in 2004 and the addition of three personnel to handle the increased workload associated with the DEFS assets.
      Capital Expenditures. In 2003, maintenance capital expenditures were $0.7 million, while expansion capital expenditures totaled $25.5 million, primarily related to the acquisition of the DEFS assets. In 2004, capital expenditures totaled $9.7 million, including $7.4 million to expand gathering systems to accommodate increased gas volumes. The remaining $2.3 million of capital expenditures represented maintenance expenditures. The increase in maintenance capital expenditures from 2003 to 2004 reflects higher spending on well connects and maintenance as a result of the addition of the DEFS assets.
General Trends and Outlook
      Our gross margins are influenced by the price of natural gas and by drilling activity in our operating regions. Increases in natural gas prices generally have a positive impact on our gross margins and conversely, a reduction in natural gas prices negatively impacts our gross margins. On average, natural gas prices for the last half of 2004 trended upward, and full-year 2004 average natural gas prices were higher than those in the first half of 2004. Average natural gas prices for 2005 were higher than the average full-year price in 2004. Volumes of natural gas on our pipelines also impact our gross margins. Increases in volumes gathered or transported positively impact our gross margins and conversely, reductions in volumes gathered or transported negatively impact our gross margins. Higher natural gas prices typically encourage drilling activity in our operating regions. We believe that natural gas prices will continue to fluctuate over the next twelve months, but will remain at levels sufficient to encourage high levels of drilling activity.
      Our gross margins are also influenced by the price of NGLs in relation to natural gas prices, and the supply of NGLs contained in natural gas delivered to us at our plants. Increases in NGL prices, relative to natural gas prices, have a positive impact on our gross margins and, conversely, a reduction in NGL prices, relative to natural gas prices, negatively impacts our gross margins. On average, NGL prices, relative to natural gas prices, for the last half of 2004 trended upward and full-year 2004 NGL prices, in relation to natural gas prices, were higher than those in the first half of 2004. Average NGL prices in relation to natural gas prices for 2005 have been above the full-year average price in 2004. The supply of NGLs contained in natural gas delivered to us at our plants also impacts our gross margins. Increases in the supply of NGLs contained in the natural gas delivered to our plants positively impact our gross margins if the price of NGLs exceeds the cost of the natural gas required to extract such NGLs. Conversely, reductions in the supply of NGLs negatively impact our gross margins under such circumstances. We believe that NGL prices, relative to natural gas prices, will continue to fluctuate, but at levels generally consistent with historical averages for full-year 2006.
      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 our outstanding borrowings fluctuate based on reserve-adjusted interbank offered market rates. Increases in interest rates have a negative impact on our distributable cash flow, and, conversely, decreases in interest rates have a positive impact on distributable cash flow. Interest rates for 2004 and 2005 have trended upwards.

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BUSINESS
General
      We are a growth-oriented midstream energy company with natural gas gathering and intrastate transmission pipeline assets and natural gas processing facilities in the Texas Gulf Coast region and in central and eastern Oklahoma.
      Our midstream assets include over 4,700 miles of natural gas gathering and transmission pipelines and four natural gas processing plants, with approximately 800 MMcf/d of combined processing capacity. Our Houston Central Processing Plant is the second largest natural gas processing plant in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. This processing plant is located approximately 100 miles southwest of Houston and has the capacity to process approximately 700 MMcf/d of natural gas. In addition to our natural gas pipelines, we own a 104-mile NGL pipeline extending from our Houston Central Processing Plant to the Houston area. The pipelines we operate include 144 miles of pipeline owned by Webb Duval, a partnership in which we own a 62.5% interest.
      Our natural gas pipelines collect natural gas from 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. Volumes delivered to our processing plants, either through our pipelines or a third-party pipeline, are treated to remove contaminants and conditioned or processed to extract mixed natural gas liquids, or NGLs. Processed or conditioned natural gas is then delivered primarily to third-party pipelines through plant interconnects, while NGLs are separated and sold to third parties.
      Since our inception in 1992, we have grown through a combination of more than 30 acquisitions and the construction of new assets. On August 1, 2005, we acquired all the membership interests in Tulsa-based ScissorTail Acquisition for $499.1 million. ScissorTail’s assets primarily consist of approximately 3,300 miles of natural gas gathering pipelines and three processing plants with current processing capacity of approximately 100 MMcf/d, located in eastern and central Oklahoma.
      On a pro forma basis for the twelve months ended September 30, 2005, we provided midstream services with respect to 771 MMcf/d of natural gas and we had $834.3 million of revenue, $131.8 million of gross margin and $89.1 million of EBITDA. For the same period, on a pro forma basis, we had $23.8 million of net income and $55.0 million of operating income. For the definitions of gross margin and EBITDA and a reconciliation of those items to the most directly comparable GAAP financial measure, please read “Summary Unaudited Pro Forma Consolidated Financial Data.”
Business Strategy
      Our management team is committed to improving cash flow from our existing assets, pursuing complementary acquisition and expansion opportunities, and managing our commodity risk exposure. Key elements of our strategy include:
  •  Pursue growth from our existing assets. Our pipelines and processing plants have excess capacity, which provides us with opportunities to increase throughput volume with minimal incremental costs. We intend 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.
 
  •  Pursue complementary acquisitions and expansion opportunities. We intend 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. 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 intend to expand our assets where appropriate to meet increased demand for our midstream services.

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  •  Reduce sensitivity of our cash flows to commodity price fluctuations. Because of the volatility of natural gas and NGL prices, we attempt to structure our contracts in a manner that allows us to achieve positive gross margins in a variety of market conditions. In our contracts for services provided by our Texas Gulf Coast Processing segment, we focus on arrangements pursuant to which we are paid a fee to condition natural gas when processing is economically unattractive. In our contracts with producers within our Texas Gulf Coast Pipelines and Mid-Continent Operations segments, we focus on arrangements pursuant to which the fee received for the services we deliver is sufficient to provide us with positive operating margins irrespective of commodity prices.
In addition, our commodity risk management activities aim to hedge our exposure to price risk and meet debt service requirements, required capital expenditures, distribution objectives and similar requirements despite fluctuations in commodity prices. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions. Please read “Summary — Recent Developments” for discussion of our recent risk management activities.
  •  Exploit the operating flexibility of our assets. Exploiting our ability to condition natural gas at our Houston Central Processing Plant, rather than fully process it, provides us with significant benefits during periods when fully processing natural gas is not economic. We continually monitor natural gas and NGL prices to quickly switch between processing and conditioning modes when it is economically appropriate to do so. In addition, we will continue to utilize our ability to reject ethane at our Houston Central Processing Plant, Paden Plant and Glenpool Plant, as market conditions warrant.
 
  •  Expand our geographic scope into new regions where our growth strategy can be applied. We intend to pursue opportunities to acquire assets in new regions where we believe growth opportunities are attractive and our business strategies are applicable.
Our Operations
      We manage our business and analyze and report our results of operations on a segment basis. Prior to the ScissorTail Acquisition, we divided our operations into two business segments: Copano Pipelines, which performs our natural gas gathering and transmission and related operations in Texas, and Copano Processing, which performs our natural gas processing, treating, conditioning and related NGL transportation operations in Texas. Following the ScissorTail Acquisition, our operations are divided into four business segments, Texas Gulf Coast Pipelines, Texas Gulf Coast Processing, Mid-Continent Operations and Corporate.

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Our Texas Gulf Coast Operations
      Our Texas Gulf Coast Operations consist of two of our operating segments, Texas Gulf Coast Pipelines and Texas Gulf Coast Processing. The following is a map of our Texas Gulf Coast region assets:
MAP

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      We have set forth in the table below summary information describing the regions in which we have pipeline systems and processing assets in the Texas Gulf Coast region.
                                                               
                        Nine Months Ended
                        September 30, 2005
                    Average    
                Existing   Throughput at   Net Average    
        Initial       Throughput   Time of   Throughput   Utilization
    Pipeline   Acquisition   Length   Capacity   Acquisition   Volumes   of
Asset   Type   Date(1)   (miles)   (Mcf/d)(2)   (Mcf/d)(3)   (Mcf/d)   Capacity
                             
Texas Gulf Coast Pipelines Segment
South Texas Region
                                                       
   
Live Oak Area
    Gathering       May 2002       114       88,000       9,179       18,813       21 %
      Gathering and                                                  
   
Agua Dulce Area(4)
    Transmission       June 1996       381       78,000       7,850       27,312       35 %
   
Hebbronville Area
    Gathering       September  1994       79       62,700       15,337       28,165       45 %
   
Karnes Area
    Gathering       August 2004       68       17,500       2,000 (5)     7,513       43 %
   
Webb/ Duval Area(6)(7)
    Gathering       February 2002       144       219,000       43,046       108,283       49 %
 
Coastal Waters Region
    Gathering       June 1992       142       37,000       1,208       3,089       8 %
 
Central Gulf Coast Region
    Gathering       August 2001       229       205,000       118,804       90,654       44 %
      Gathering and                                                  
 
Upper Gulf Coast Region
    Transmission       April 1997       230       139,000       33,748       36,870       27 %
                                                         
     
Total
                    1,387                       320,699          
                                                         
Texas Gulf Coast Processing Segment
                                                       
 
Houston Central Processing Plant
    Processing       August 2001                                          
   
Inlet volumes
                                    626,764 (8)     529,342          
                                                         
   
NGLs produced
                                    10,406  Bbls/d (8)     13,661          
                                                         
 
Sheridan NGL Pipeline
    NGL Transportation       August 2001       104               2,648  Bbls/d (8)     3,875          
                                                         
 
(1) The initial acquisition date is the date that we first commenced operations with respect to any area, region or facility.
 
(2) Many capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacity and/or other facility upgrades including, for example, larger dehydration capacity.
 
(3) Reflects average throughput for the first month in which we operated the assets.
 
(4) Throughput volumes presented in the table are net of intercompany transactions. Gross volumes and utilization of capacity in this area totaled 27,667 Mcf/d and 35%, respectively, for the nine months ended September 30, 2005.
 
(5) Only reflects throughput volumes on our Runge Gathering System that we acquired and integrated in December 2004. No historical throughput information is available for the Karnes County Gathering System (acquired in August 2004) because no throughput existed in the month prior to acquisition.
 
(6) Our Webb/ Duval Area consists of the Webb/ Duval Gathering System and two smaller gathering systems, which are owned by Webb Duval, an unconsolidated subsidiary in which we hold a 62.5% interest.
 
(7) Throughput volumes presented in the table are net of affiliate transactions. Gross volumes and utilization of capacity in this area totaled 129,658 Mcf/d and 59%, respectively, for the nine months ended September 30, 2005.
 
(8) Represents volumes for the month of June 2001. In July 2001, volumes began to be transported from our South Texas Region to the KMTP Laredo-to -Katy pipeline, thereby increasing the volume of NGLs produced by our Houston Central Processing Plant and transported on our Sheridan NGL line.
Texas Gulf Coast Pipelines Segment
      We own approximately 1,387 miles of pipelines used for natural gas gathering and transmission, including approximately 144 miles of pipeline owned by Webb Duval. For the nine months ended September 30, 2005 and the year ended December 31, 2004, we averaged net throughput volumes of 320,699 Mcf/d and 325,407 Mcf/d, respectively, of natural gas. Our facilities are operated in four separate operating regions as described below.
South Texas Region
      The South Texas Region consists of eight wholly-owned gathering and intrastate transmission systems totaling approximately 640 miles of pipelines operating in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces and San Patricio Counties, Texas. This region is composed of several operating pipeline systems including the Live Oak System, the Clayton Pipeline, the Agua Dulce System, the

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Nueces County System, the Mesteña Grande System, the Hebbronville Pipeline, the Karnes County Gathering System and the Runge Gathering System. This region is managed from our field office in Alice, Texas. In addition, our employees in this region are responsible for the operations of Webb/ Duval Gatherers, as more fully described below.
Live Oak Area
      Our Live Oak Area is comprised of two gathering systems, the Live Oak System and the Clayton Pipeline.
      Live Oak System. The Live Oak System is an approximately 56-mile pipeline system that gathers natural gas from fields located in Live Oak County, Texas. The Live Oak System is composed of a 12-inch diameter mainline and two 8-inch diameter main gathering lateral lines, the Bennett lateral and the Patteson lateral, which extend into southern and eastern Live Oak County. The system also includes several smaller lines that range in size from two inches to eight inches in diameter. We currently gather natural gas from approximately 28 active receipt meters representing 21 producers and four shippers connected to our Live Oak System. All of the natural gas from the Live Oak System is compressed, dehydrated and delivered to the KMTP Laredo-to -Katy pipeline for treating, conditioning and/or processing at our Houston Central Processing Plant.
      In February 2002, we expanded our compression and dehydration facilities providing a throughput capacity of 50,000 Mcf/d. We currently operate 1,710 horsepower of compression and 40,000 Mcf/d of dehydration capacity. Average throughput volume on this system was 21,278 Mcf/d for the year ended December 31, 2004 and 14,319 Mcf/d for the nine months ended September 30, 2005. The Live Oak System has a capacity of 36,000 Mcf/d.
      Clayton Pipeline. The Clayton Pipeline is an approximately 58-mile pipeline extending through Atascosa, Live Oak and Duval Counties, Texas. The northern 34 miles consists of 10-inch diameter pipeline and the southern 22 miles consists of 16-inch diameter pipeline. There are approximately two miles of 3-inch to 6-inch diameter feeder pipelines. We currently transport natural gas on the Clayton Pipeline from four active receipt meters including the Pueblo Midstream Fashing plant in Atascosa County, representing three producers as well as the Fashing plant tailgate interconnect. Natural gas is delivered to either Houston Pipe Line Company or Natural Gas Pipeline Company of America (“NGPL”). The Clayton Pipeline has no compression or dehydration facilities.
      Average throughput volume on the Clayton Pipeline was 2,002 Mcf/d for the year ended December 31, 2004 and 4,494 Mcf/d for the nine months ended September 30, 2005. The Clayton Pipeline has a capacity of 52,000 Mcf/d.
Agua Dulce Area
      Our Agua Dulce Area consists of two primary pipeline assets, the Agua Dulce System and the Nueces County System.
      Agua Dulce System. The Agua Dulce System is an approximately 240-mile gathering system located in Duval, Jim Wells and Nueces Counties, Texas. The Agua Dulce System is composed of (i) the East Duval lateral, a 17-mile, 10-inch diameter mainline that originates near Agua Dulce, Texas in Jim Wells County, and terminates at an interconnect with the Webb/ Duval Gathering System and (ii) several distinct gathering systems that deliver natural gas to the East Duval lateral. There are approximately 240 miles of 2-inch to 12-inch diameter gathering pipelines that supply the East Duval lateral. We currently gather natural gas from 43 active receipt meters, representing 36 producers. Since purchasing the system, we have added approximately 9 miles of pipeline, including the 6-mile, 12-inch diameter line that connected the system to the Webb/ Duval Gathering System in 2002. We currently have 5,110 horsepower of compression and 44,000 Mcf/d of dehydration capacity installed on this system. Natural gas is gathered and transported through the Agua Dulce System into the Webb/ Duval Gathering System, which can deliver this natural gas into the KMTP Laredo-to -Katy pipeline. The Agua Dulce System has inactive interconnects with Enterprise

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Products Partners, L.P., Humble Gas Pipeline Company (an affiliate of ExxonMobil), and Duke Energy Field Services.
      Average net throughput volume on this system was 22,196 Mcf/d for the year ended December 31, 2004 and 21,766 Mcf/d for the nine months ended September 30, 2005. The Agua Dulce System has an estimated capacity of 37,000 Mcf/d.
      Nueces County System. The Nueces County System is an approximately 141-mile pipeline system that gathers natural gas in Nueces and San Patricio Counties, Texas. The Nueces County System is composed of gathering and transmission lines ranging in size from two inches to 12 inches in diameter. The Nueces County System currently gathers natural gas from 14 active receipt meters representing nine producers. Natural gas from this system is gathered and delivered to Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.) and to our Agua Dulce System. We currently have 85 horsepower of compression and 33,000 Mcf/d of dehydration capacity installed on this system.
      Average throughput volume on this system was 10,203 Mcf/d for the year ended December 31, 2004 and 5,546 Mcf/d for the nine months ended September 30, 2005. The Nueces County System has an estimated capacity of 41,000 Mcf/d under current operating pressures.
Hebbronville Area
      There are two major pipelines that encompass the Hebbronville area, the Mesteña Grande System and the Hebbronville Pipeline.
      Mesteña Grande System. The Mesteña Grande System is an approximately 56-mile pipeline system located in the southern portion of Jim Hogg County and the northern half of Duval County, Texas. The Mesteña Grande System currently gathers natural gas from 17 active receipt meters, representing five producers and one shipper. This system consists of pipelines ranging in size from 4 inches to 8 inches in diameter. All natural gas gathered from the Mesteña Grande System is transported for delivery to KMTP via our Hebbronville Pipeline. We currently have 4,020 horsepower of compression installed on this system and 80,000 Mcf/d of dehydration capacity.
      Hebbronville Pipeline. The Hebbronville Pipeline was constructed by us in 2001 and is an approximately 23-mile pipeline comprised of 12-inch diameter pipeline and 16-inch diameter pipeline, which transports all of the natural gas from the Mesteña Grande System for delivery to the KMTP Laredo-to -Katy pipeline. The Hebbronville Pipeline has two active receipt meters representing one shipper. There is no installed compression or dehydration on this pipeline.
      Average throughput volume on these pipelines was 29,423 Mcf/d on a combined basis for the year ended December 31, 2004 and 28,165 Mcf/d for the nine months ended September 30, 2005. The Mesteña Grande System currently has an estimated capacity of 62,700 Mcf/d and the Hebbronville Pipeline has an estimated capacity of 250,000 Mcf/d. Without additional compression, however, the combined capacity of these pipelines is limited to 62,000 Mcf/d.
Karnes Area
      The Karnes Area is comprised of two natural gas gathering systems, the Karnes County Gathering System and the Runge Gathering System.
      Karnes County Gathering System. The Karnes County Gathering System is an approximately 15-mile pipeline operating in northern Bee and southern Karnes Counties, Texas. This system is comprised of natural gas pipelines ranging in size from 10 inches to 16 inches in diameter. The Karnes County Gathering System gathers natural gas from one active receipt meter connected to a third party. Natural gas transported on the Karnes County Gathering System is delivered to the KMTP Laredo-to -Katy pipeline and is processed or conditioned at our Houston Central Processing Plant. We currently have 2,060 horsepower of compression installed on this system.

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      Runge Gathering System. The Runge Gathering System is comprised of 53 miles of natural gas pipelines located in Bee, DeWitt, Goliad and Karnes Counties, Texas. This system is comprised of 37 miles of natural gas pipelines ranging in size from 4 inches to 8 inches and a 16-mile 4-inch natural gas liquids pipeline that was converted to natural gas service to provide delivery of natural gas from the Runge Gathering System to our Karnes County Gathering System. Natural gas from the Runge Gathering System is gathered and redelivered into the Karnes County Gathering System which is then delivered to the KMTP Laredo-to -Katy pipeline and is processed or conditioned at our Houston Central Processing Plant. This system has six active receipt meters.
      Average throughput volume on these pipelines was 9,771 Mcf/d on a combined basis for the period from acquisition through December 31, 2004. Average throughput volume on these pipelines was 7,513 Mcf/d for the nine months ended September 30, 2005.
Webb/ Duval Area
      Our Webb/ Duval Area is comprised of the Webb/ Duval Gathering System, the Olmitos Gathering System and the Cinco Compadres Gathering System, each of which is owned by Webb Duval, a general partnership that we operate and in which we hold a 62.5% interest. As the holder of a 62.5% interest in the partnership that owns these pipeline systems, we operate these systems subject to certain rights of the other partners, including the right to approve capital expenditures in excess of $0.1 million, financing arrangements by the partnership or any expansion projects associated with these systems. In addition, each partner has the right to use its pro rata share of pipeline capacity on these systems subject to applicable ratable take and common purchaser statutes.
      Webb/ Duval Systems. The Webb/ Duval Gathering System is a 121-mile pipeline located in Webb and Duval Counties, Texas, and is comprised of 3-inch and 16-inch diameter pipelines. Following our construction of a 6-mile, 12-inch diameter pipeline in 2002, the Webb/ Duval Gathering System connects our Agua Dulce System to the KMTP Laredo-to -Katy pipeline. We currently have 30 active receipt meters connected to the Webb/ Duval Gathering System, representing 11 shippers. We currently have 7,468 horsepower of installed compression and no dehydration on this system. The Olmitos Gathering System and the Cinco Compadres Gathering System are smaller non-contiguous gathering systems that are part of Webb Duval’s assets. The Olmitos Gathering System is a 14-mile pipeline located in Webb County, Texas, and is comprised of 4-inch to 8-inch diameter pipelines. The Cinco Compadres Gathering System is a 9-mile pipeline located in Webb County, Texas, and is comprised of 3-inch to 6-inch diameter pipelines.
      Average total throughput volume on these combined systems including volumes delivered by our Agua Dulce System was 126,305 Mcf/d for the year ended December 31, 2004 and 129,658 Mcf/d for the nine months ended September 30, 2005. Excluding the volume received from our Agua Dulce System described previously, the average throughput volume on these systems was 104,437 Mcf/d for the year ended December 31, 2004 and 108,283 Mcf/d for the nine months ended September 30, 2005. Differences in volumes between the Webb/ Duval Gathering Area and the Agua Dulce systems are attributable to gas consumed as fuel during dehydration and compression, ordinary pipeline system gains and losses and the fact that the Agua Dulce System used alternate interconnects before its connection during 2002 to the Webb/ Duval Gathering System. The Webb/ Duval Gathering System has an estimated current capacity of 219,000 Mcf/d. We generate gross margins from transportation of natural gas across these majority-owned pipelines.
Coastal Waters Region
      The Coastal Waters Region is comprised of two pipeline systems, the Copano Bay System and the Encinal Channel Pipeline, consisting of approximately 142 miles of pipelines operating both onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. This region is managed from our field office in Lamar, Texas.
      Copano Bay System. The Copano Bay System currently comprises approximately 119 miles of natural gas pipelines, which range in size from three inches to 12 inches in diameter. Currently, the Copano Bay System gathers natural gas from the offshore Matagorda Island Block 721 area, Aransas and Copano Bays,

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and adjacent onshore lands through Aransas Bay and onshore at Rockport, Texas. Natural gas and condensate are separated at our Lamar separation and dehydration facility, and the natural gas is delivered to Enterprise Products Partners, L.P./ Channel at Lamar, Texas. The condensate is stored and redelivered to producers and shippers who then truck the product to market. The Copano Bay System gathers or transports substantially all of the natural gas in the Copano Bay and Aransas Bay area. The throughput capacity of this system is 37,000 Mcf/d and has 25,000 Mcf/d of dehydration capacity. The Copano Bay System has ten active receipt meters, representing nine producers and one shipper.
      Average throughput volume on this system was 11,403 Mcf/d for the year ended December 31, 2004 and 3,089 Mcf/d for the nine months ended September 30, 2005.
      Encinal Channel Pipeline. The Encinal Channel Pipeline is an approximately 23-mile pipeline that is currently inactive. The Encinal Channel Pipeline measures three inches to 12 inches in diameter and is located in Nueces and San Patricio Counties, Texas. The Encinal Channel Pipeline currently has an estimated throughput capacity of 145,000 Mcf/d. There is no installed compression or dehydration on this pipeline. We believe inland bay lease sales will ultimately provide natural gas purchase and transportation opportunities for this pipeline.
Central Gulf Coast Region
      The Central Gulf Coast Region is composed of two intrastate natural gas gathering systems totaling approximately 229 miles and operating in Colorado, Dewitt, Lavaca and Wharton Counties, Texas. This region is operated from our Houston Central Processing Plant located approximately 100 miles southwest of Houston. Interconnects at the tailgate of our Houston Central Processing Plant include KMTP, Tennessee Gas Pipeline, Texas Eastern Transmission and Houston Pipe Line Company.
      Sheridan System. The Sheridan System consists of approximately 71 miles of natural gas gathering lines ranging in size from four inches to 10 inches in diameter, and gathers natural gas from 23 active receipt meters and one third-party pipeline interconnect located in Colorado and Lavaca Counties, Texas, representing 15 producers and three shippers. There is no installed compression or dehydration on this system. Natural gas from the Sheridan System is gathered and transported to our Houston Central Processing Plant for treatment of carbon dioxide, processing and ultimate delivery into the interconnects at the tailgate of our processing plant. The Sheridan System also has a pipeline interconnect with the Enterprise Products’ Chesterville System. Average throughput volume on this system was 18,338 Mcf/d for the year ended December 31, 2004 and 28,137 Mcf/d for the nine months ended September 30, 2005. The Sheridan System has an estimated capacity of 45,000 Mcf/d.
      Provident City System. This system consists of approximately 158 miles of natural gas gathering lines ranging in size from three inches to 14 inches in diameter, and gathers natural gas from 74 receipt points and one third-party pipeline interconnect located in Colorado, DeWitt, Lavaca and Wharton Counties, Texas, representing 45 producers and seven shippers. There is no compression or dehydration installed on this system. The Provident City System has a pipeline interconnect with Duke Energy Field Services’ San Jacinto Pipeline System. Average throughput volume on this system was 56,137 Mcf/d for the year ended December 31, 2004 and 62,517 Mcf/d for the nine months ended September 30, 2005. The Provident City System has an estimated capacity of 160,000 Mcf/d.
Upper Gulf Coast Region
      Our Upper Gulf Coast Region is composed of three pipeline systems consisting of approximately 230 miles of pipeline used for gathering, transportation and sales of natural gas in Houston, Walker, Grimes, Montgomery and Harris Counties, Texas. This region is managed from our field office in Conroe, Texas.
      Sam Houston System. The Sam Houston System includes approximately 125 miles of natural gas pipeline that gathers natural gas and receives natural gas from other pipelines for ultimate delivery to markets on the system. This gathering and transportation pipeline ranges in size from four inches to 12 inches in

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diameter. We currently gather natural gas from 16 active receipt meters and five third-party pipeline interconnects, representing 13 producers and three shippers.
      The Sam Houston System has interconnects with Houston Pipe Line Company, Lone Star Pipeline Company, KMTP, Vantex Gas Pipeline Company and Texas Eastern Transmission. The Sam Houston System delivers natural gas to multiple CenterPoint Energy city gates in The Woodlands, Conroe and Huntsville, Texas, to Universal Natural Gas, a gas company providing services to residential markets in southern Montgomery County, Texas and to Entergy’s Lewis Creek Generating Plant and several industrial consumers. There is no compression or dehydration installed on this pipeline system. Average net throughput volume on this system was 33,489 Mcf/d for the year ended December 31, 2004 and 34,036 Mcf/d for the nine months ended September 30, 2005. The Sam Houston System has an estimated capacity of approximately 119,000 Mcf/d.
      Grimes County System. The Grimes County System is an approximately 77-mile natural gas gathering system located in Grimes County, Texas, which consists of natural gas pipelines ranging in size from two inches to 12 inches in diameter. We currently gather natural gas from 12 active receipt meters representing six producers, and deliver all of the natural gas to our Sam Houston System. There is 311 horsepower of compression and no active dehydration on this pipeline system.
      Average throughput volume on this system was 2,514 Mcf/d for the year ended December 31, 2004 and 2,546 Mcf/d for the nine months ended September 30, 2005. The Grimes County System has an estimated capacity of 23,000 Mcf/d.
      Lake Creek Pipeline. The Lake Creek Pipeline is an approximately 28-mile natural gas pipeline system located in Harris and Montgomery Counties, Texas. The Lake Creek Pipeline is comprised of 6-inch and 8-inch diameter natural gas pipelines. This pipeline has three receipt points and a bi-directional receipt and delivery point with Houston Pipe Line Company near the Bammel Storage field in Harris County.
      The majority of the natural gas transported on this pipeline is delivered to CenterPoint Energy at delivery points serving the western portion of The Woodlands, Texas and the surrounding area. Natural gas is also delivered to Universal Natural Gas. Average throughput volume on this system was 4,216 Mcf/d for the year ended December 31, 2004 and 288 Mcf/d for the nine months ended September 30, 2005. The Lake Creek Pipeline has an estimated capacity of 20,000 Mcf/d.
Texas Gulf Coast Processing Segment
      The Texas Gulf Coast Processing segment includes our Houston Central Processing Plant located near Sheridan, Texas in Colorado County and our Sheridan NGL Pipeline that runs from the tailgate of the processing plant to the Houston area.
      Houston Central Processing Plant. Our Houston Central Processing Plant is the third largest in the state of Texas in terms of throughput capacity and the second largest and the most fuel efficient processing plant in the areas in which we operate. Our Houston Central Processing Plant removes NGLs from the natural gas supplied by the KMTP Laredo-to -Katy pipeline, which it straddles, and the pipelines in our Central Gulf Coast Region gathering systems and fractionates the NGLs into separate marketable products for sale to third parties. The Houston Central Processing Plant was originally constructed in 1965 by Shell and was comprised of a single refrigerated lean oil train and a fractionation facility. The plant was modified by Shell in 1985 with the addition of a second refrigerated lean oil train and in 1986 with the addition of a cryogenic turbo-expander train. This 700 MMcf/d gas processing plant includes 6,689 horsepower of inlet compression, 8,400 horsepower of tailgate compression, a 700 gallon per minute amine treating system for removal of carbon dioxide and low-level hydrogen sulfide, two 250 MMcf/d refrigerated lean oil trains, one 200 MMcf/d cryogenic turbo-expander train, a 25,000 Bbls/d NGL fractionation facility, and 882,000 gallons of storage capacity for propane, butane and natural gasoline mix and stabilized condensate. The plant also has multiple tailgate interconnects for redelivery of natural gas with KMTP, Houston Pipe Line Company (a subsidiary of Energy Transfer Partners, L.P.), Tennessee Gas Pipeline Company and Texas Eastern Transmission. In addition, at the tailgate of the plant, we operate our Sheridan NGL Pipeline for transporting NGLs and

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TEPPCO operates an 8-inch diameter crude oil and stabilized condensate pipeline that runs to refineries in the greater Houston area. In addition, we have an interconnect to a 6-inch diameter pipeline for transportation of ethane and propane operated by a subsidiary of Dow Chemical to Dow’s Freeport facility. Our Houston Central Processing Plant and related facilities are located on a 163-acre tract of land, which we lease under three long-term lease agreements.
      In 2003, we modified the processing plant to provide natural gas conditioning capability by 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 one of our steam-driven turbines when we are conditioning natural gas. These modifications provide us with the capability to process gas only to the extent required to meet pipeline hydrocarbon dew point specifications. Our ability to condition gas, rather than fully process it, provides us with significant benefits during periods when processing is not economic (when the price of natural gas is high compared to the price of NGLs), including:
  •  providing us with the ability to minimize the level of NGLs removed from the natural gas stream during periods when prices are high relative to NGL prices; and
 
  •  allowing us to operate our Houston Central Processing Plant more efficiently at a much reduced fuel consumption rate while still meeting downstream pipeline hydrocarbon dew point specifications.
      As a result, during these periods the combination of reduced NGL removal and reduced fuel consumption at our plant allows us to preserve a greater portion of the value of the natural gas.
      Our Houston Central Processing Plant has an inlet capacity of approximately 700 MMcf/d and had an average throughput of 529 MMcf/d for the year ended December 31, 2004 and an average daily throughput of 529 MMcf/d for the nine months ended September 30, 2005. The average daily volume of ethane and propane delivered from the plant to the Dow NGL pipeline was 10,667 Bbls/d for the year ended December 31, 2004 and 9,190 Bbls/d for the nine months ended September 30, 2005. The average daily volume of butane and NGLs delivered to the Sheridan NGL pipeline was 4,322 Bbls/d and 3,875 Bbls/d for the year ended December 31, 2004 and the nine months ended September 30, 2005, respectively. The average daily volume of stabilized condensate delivered from the plant to the TEPPCO crude oil pipeline was 379 Bbls/d for the year ended December 31, 2004 and 662 Bbls/d for the nine months ended September 30, 2005.
      Sheridan NGL Pipeline. Our 104-mile, 6-inch diameter Sheridan NGL pipeline originates at the tailgate of our Houston Central Processing Plant and currently delivers NGLs into the Enterprise Products Partners’ Seminole Pipeline for ultimate redelivery for further transportation and fractionation. The line has a current capacity of 20,840 Bbls/d of NGLs, which we believe could be increased with the installation of additional pump facilities. Average throughput volume on this system was 4,322 Bbls/d for the year ended December 31, 2004 and 3,875 Bbls/d for the nine months ended September 30, 2005.
Competition in Our Texas Gulf Coast Operating Region
      The natural gas gathering, transmission, treating, processing and marketing industries are highly competitive. 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. 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 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 gives us an advantage in competing 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 due in part to the elimination of some field equipment and greater economies of scale at our Houston Central Processing Plant.

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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. In addition, with respect to natural gas customers attached to our pipeline systems, we are able to vary quantities of natural gas delivered to customers in response to market demands.
      The primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. 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.
      Many of our competitors in the Texas Gulf Coast region have capital resources and control supplies of natural gas greater than ours. Our major competitors for natural gas supplies and markets in our four Texas operating regions include Enterprise Products Partners, L.P., Lobo Pipeline Company (an affiliate of ConocoPhillips), KMTP, Duke Energy Field Services, Crosstex Energy, and Houston Pipe Line Company. Our primary competitors for our Texas Gulf Coast Processing segment are Enterprise, ExxonMobil and Duke Energy Field Services.
Texas Gulf Coast Natural Gas Supply
      Our Texas assets are located in areas that have experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We generally do not obtain independent evaluations of 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 Texas systems or the anticipated life of such producing reserves. We have engaged Energy Strategy Partners to document production trends within a 10-mile radius of all of our pipelines based upon information obtained from regulatory filings with the TRRC. We believe that a 10-mile radius provides a valuable perspective of the number of wells adjacent to our pipelines as well as potential drilling activity near our pipelines. While it may not be cost-effective for us to connect a single well located within 10 miles of our gathering systems, high drilling activity within this radius may signal a new natural gas field, which could yield multiple well attachment opportunities. Additionally, a 10-mile radius also provides a larger sampling of data for statistical analysis of drilling activity in our operating regions.
      Using the data described above, we have constructed the following chart, which illustrates production trends from active wells adjacent to our pipelines in our Texas Gulf Coast Pipelines segment (within a ten-mile radius) from 1990 through September 30, 2005. Production levels are presented as average daily volumes stated in MMcf/d. The years shown inside the graph are the initial production years of the wells responsible for the shaded volumes of natural gas. The production amounts shown on this chart do not represent volumes

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of natural gas that flowed through our pipelines, but total production from active wells within the ten-mile radius described above.
(PRODUCTION TREND CHART)
      During the nine months ended September 30, 2005, our top producers by volume of natural gas were Dominion OK TX Exploration, Noble Energy, Mesteña Operating, Westport Oil and Gas Company (a subsidiary of Kerr-McGee), and Edge Petroleum, which collectively accounted for approximately 39% of the natural gas delivered to our natural gas gathering and intrastate pipeline systems during that period.
      We contract for supplies of natural gas from producers primarily under two types of arrangements, natural gas purchase contracts and fee-for-service contracts. The primary term of each contract varies significantly, ranging from one month to the life of the dedicated production. The specific terms of each natural gas supply contract are based upon a variety of factors including gas quality, pressure of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. For a detailed discussion of our contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Our Contracts — Texas Gulf Coast Pipelines Contracts.”
      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 that was previously transported on other gathering systems.
Kinder Morgan Texas Pipeline
      KMTP is an intrastate natural gas pipeline system that is principally located in the Texas Gulf Coast region. KMTP transports natural gas from producing fields in South Texas, the Texas Gulf Coast and the Gulf of Mexico to markets in southeastern Texas. KMTP acts as a seller of natural gas as well as a transporter. We utilize KMTP as a transporter because our Houston Central Processing Plant straddles its 30-inch diameter Laredo-to -Katy pipeline. By using KMTP as a transporter, we can transport natural gas from many of our pipeline systems to our processing plant and downstream markets. Under our contractual arrangement related 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. We refer to the natural gas delivered into KMTP’s pipeline from sources other than our gathering systems as “KMTP Gas.” Because the extraction of NGLs from the natural gas stream during processing or conditioning reduces the Btus of the natural gas, our arrangement with KMTP requires us to purchase natural gas at market prices to replace the loss in Btus. Pursuant to an amendment to this

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contract with KMTP, effective January 1, 2004, we pay a fee to KMTP based on the NGL content of the KMTP Gas only during periods of favorable processing margins. In addition, the amendment provides that during periods of unfavorable processing margins, KMTP pays us a fixed fee plus an additional payment based on the index price of natural gas. Our contract arrangement relating to KMTP Gas expires on August 31, 2006, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior notice. We are currently in the process of discussing mutually beneficial revisions and an extension to our contract with KMTP Gas.
      For the nine months ended September 30, 2005, approximately 83% of the natural gas volumes processed or conditioned at our Houston Central Processing Plant were delivered to the plant through the KMTP Laredo-to -Katy pipeline while the remaining 17% were delivered directly into the plant from our gathering systems. Of the natural gas delivered into the plant from the KMTP Laredo-to -Katy pipeline, approximately 26% was delivered from gathering systems controlled by us and 74% was delivered into KMTP’s pipeline from other sources. Of the total volume of NGLs extracted at the plant during this period, 40% was attributable to KMTP Gas, while 60% was attributable to gas from gathering systems controlled by us, including our gathering systems connected directly to the plant.
Mid-Continent Operations Segment
      On August 1, 2005, we completed the acquisition of ScissorTail. We refer to the business and properties of ScissorTail as our Mid-Continent Operations segment.

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      The following map represents our Mid-Continent Operations segment:
MAP

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      We have set forth in the table below summary information describing our Mid-Continent Operations gathering systems and processing assets:
                                                     
                    Nine Months Ended
                    September 30, 2005
                Average    
            Existing   Throughput   Average    
    Initial       Throughput   Volumes at Time   Throughput   Utilization
    Acquisition   Length   Capacity   of Acquisition   Volumes   of
Asset   Date(1)   (miles)   (Mcf/d)(2)   (Mcf/d)(3)   (Mcf/d)   Capacity
                         
Gathering Pipelines
                                               
 
Stroud System
    July 2000       709       102,000       42,485       59,632       58.5 %
 
Osage System
    June 2003       549       17,000       11,826       12,780       75.2 %
 
Milfay System
    June 2003       369       15,000       9,460       12,029       80.2 %
 
Glenpool System
    June 2003       1,014       23,500       10,538       9,760       41.5 %
 
Twin Rivers System
    June 2003       526       16,000       12,555       11,547       72.2 %
 
Mountain System(4)
    June 2003       164       45,000       22,652       19,781       43.9 %
                                     
   
Total
            3,331       218,500       109,516       125,529          
                                     
                                             
                Nine Months Ended
                September 30, 2005
            Average    
        Existing   Inlet   Average    
    Initial   Throughput   Volumes at Time   Inlet   Utilization
    Acquisition   Capacity   of Acquisition   Volumes   of
Asset   Date(1)   (Mcf/d)(2)   (Mcf/d)(3)   (Mcf/d)   Capacity
                     
Processing Plants
                                       
 
Paden
    June 2001 (5)     60,000             31,635       52.7 %
 
Milfay
    June 2003       15,000       8,661       10,962       73.1 %
 
Glenpool
    June 2003       25,000       9,941       9,009       36.0 %
                               
   
Total
            100,000       18,602       51,606          
                               
 
(1) The initial acquisition date is the date that ScissorTail first commenced operations with respect to any system or facility.
 
(2) Many capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacity and/or other facility upgrades including, for example, larger dehydration capacity.
 
(3) Reflects average throughput for the first month in which ScissorTail operated the assets.
 
(4) The Mountain System consists of three systems: Blue Mountain, Cyclone Mountain and Pine Mountain.
 
(5) Reflects date of construction by ScissorTail.
     Our Mid-Continent Operations pipeline gathering systems include: Stroud, Osage, Milfay, Glenpool, Twin Rivers, Blue Mountain, Cyclone Mountain and Pine Mountain. The Paden Plant, Glenpool Plant and Milfay Plant are integrated within the Stroud System, Glenpool System and Milfay System, respectively.
Stroud System
      The Stroud gathering system is comprised of approximately 709 miles of pipeline ranging from two inches to 12 inches in diameter. The Stroud system is located in Payne, Lincoln, Oklahoma, Pottawatomie, Seminole, and Okfuskee counties, Oklahoma. Average throughput for the nine month period ended September 30, 2005 was 59,632 Mcf/d. Approximately 25,846 Mcf/d of these volumes was delivered to Enogex’s Harrah Plant and the remainder, approximately 33,786 Mcf/d, was delivered to our Paden Plant. As of September 30, 2005, there were approximately 432 active receipt meters connected to the Stroud gathering system.
      The natural gas supplied to the Stroud system is generally under acreage dedication and long-term agreements with remaining terms ranging from two to fifteen years. New Dominion, the largest producer for our Mid-Continent Operations segment, recently executed a 10-year extension of its dedication to us. Under

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this agreement, existing and future developments on 1.1 million acres in the Stroud system are dedicated to us to the year 2020. We also have dedications from two additional producers covering production from an aggregate of over 250,000 acres pursuant to contracts ending between 2009 and 2011.
      For the nine months ended September 30, 2005, 56.7% of the net average throughput volumes from the Stroud System was processed at our Paden Plant. The Paden Plant is a turbo-expander cryogenic facility with current natural gas throughput capacity of approximately 60,000 Mcf/d. Placed into service in June 2001, the plant has the ability to reduce the ethane extracted from natural gas processed, or “reject ethane”. The ability to either retain ethane or reject it provides us with an advantage as ethane may be more valuable in liquid form (after extraction from natural gas) or retained within the gas stream, depending on market prices. For the nine months ended September 30, 2005, average inlet volumes were 31,635 Mcf/d and approximately 3,673 Bbls/d of raw mix NGLs were produced, together with approximately 26,513 MMBtu/d of residue gas and 888 Bbls/d of condensate. Field compression provides the necessary pressure at the inlet, so inlet compression is not required. The Paden Plant has an amine sweetening process unit for removal of hydrogen sulfide and carbon dioxide but this unit has not been utilized to date due to current upstream treatment by producers. The plant also has inlet condensate facilities including vapor recovery and a condensate stabilizer. The residue natural gas from the Paden Plant is delivered into Enogex’s natural gas transmission system for redelivery to NGPL-Texok and CenterPoint-East Zone and the NGLs are delivered to Oneok Hydrocarbon, L.P. Due to increasing production volumes around the Paden Plant, the plant is expected to be operating at near full capacity by the end of 2006. The remaining throughput volumes from the Stroud System are processed at Enogex’s Harrah Plant under an agreement with Enogex. For the nine months ended September 30, 2005, our average daily inlet volumes processed at the Enogex Harrah Plant were 22,771 Mcf/d and approximately 2,750 Bbls/d of raw mix NGLs were produced, together with approximately 16,634 MMBtu/d of residue gas and 244 Bbls/d of condensate.
      The Stroud System has approximately 112 active purchase and gathering contracts.
Osage System
      The Osage gathering system is comprised of approximately 549 miles of pipeline ranging from two inches to eight inches in diameter. The Osage System is located in Osage, Pawnee, Payne, Washington and Tulsa counties, Oklahoma. Average throughput for the nine months ended September 30, 2005 was 12,780 Mcf/d. As of September 30, 2005, there were approximately 169 active receipt meters connected to the Osage gathering system. Given the lean nature of the wellhead production, the majority of the natural gas gathered on the Osage System is not processed. Downstream pipeline interconnects include Enogex, OGT and Keystone Gas. Gas that is delivered to Keystone Gas is processed by Duke Energy Field Services at their Kingfisher Plant and we receive a share of natural gas liquids and residue gas. For the nine months ended September 30, 2005, our average daily inlet volumes processed at the Duke Kingfisher Plant were 623 Mcf/d and approximately 69 Bbls/d of raw mix NGLs were produced, together with approximately 416 MMBtu/d of residue gas and 4 Bbls/d of condensate.
      The primary producing areas that supply the Osage System are located in the southern part of the system. The area served by the Osage System is mature and current drilling activity is focused on the development of coalbed methane gas produced in the Rowe formation.
      The Osage System has approximately 147 active purchase and gathering contracts.
Milfay System
      The Milfay gathering system is comprised of approximately 369 miles of pipeline ranging from two inches to eight inches in diameter. The Milfay System is located in Tulsa, Creek, Payne, Lincoln, and Okfuskee counties, Oklahoma. Average throughput for the nine months ended September 30, 2005 was 12,029 Mcf/d. As of September 30, 2005, there were approximately 238 active receipt meters connected to the Milfay gathering system.

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      We believe that there will be continued volume growth in the Milfay system as a result of continued development of the Bartlesville, Hunton and Dutcher formations. This growth is consistent with significant volume increases from the first nine months of 2004 to the first nine months of 2005 due to wells drilled and successfully completed in the Bartlesville formation.
      Substantially all of the gas from the Milfay gathering system is delivered to the Milfay processing plant, which consists of a propane refrigeration facility with natural gas throughput capacity of approximately 15,000 Mcf/d. Average inlet volumes for the nine months ended September 30, 2005 were 10,962 Mcf/d and approximately 826 Bbls/d of raw mix NGL was produced, along with about 9,491 MMBtu/d of residue gas. Residue natural gas is delivered into the Oneok Gas Transmission (“OGT”) system and the NGLs are delivered to Oneok Hydrocarbon, L.P.
      The Milfay System has approximately 185 active purchase and gathering contracts.
Glenpool System
      The Glenpool gathering system is comprised of approximately 1,014 miles of pipeline ranging from two inches to 10 inches in diameter. The Glenpool System is located in Tulsa, Wagoner, Muskogee, McIntosh, Okfuskee, Okmulgee and Creek counties, Oklahoma. Average throughput for the nine months ended September 30, 2005 was 9,760 Mcf/d. As of September 30, 2005, there were approximately 405 active receipt meters connected to the Glenpool System.
      Substantially all of the gas from the Glenpool gathering system is delivered to the Glenpool processing plant, which consists of a cryogenic facility with natural gas throughput capacity of approximately 25,000 Mcf/d. Average inlet volumes for the nine months ended September 30, 2005 were 9,009 Mcf/d and approximately 547 Bbls/d of raw mix NGLs were produced, along with about 8,620 MMBtu/d of residue natural gas. Residue natural gas is delivered into either OGT or the American Electric Power Riverside Power Plant and the NGLs are delivered to Oneok Hydrocarbon, L.P.
      The Glenpool System has approximately 303 active purchase and gathering contracts.
Twin Rivers System
      The Twin Rivers gathering system is comprised of approximately 526 miles of pipeline ranging from two inches to 12 inches in diameter. The Twin Rivers System is located in Okfuskee, Seminole, Hughes, Pontotoc and Coal counties, Oklahoma. Average throughput for the nine month period ended September 30, 2005 was 11,547 Mcf/d. As of September 30, 2005, there were approximately 312 active receipt meters connected to the system and substantially all of the system’s volumes are delivered to Enogex’s Wetumka Processing Plant. The residue natural gas is delivered into Enogex’s natural gas transmission system for redelivery to CenterPoint-East Zone and the NGLs are sold to Enogex. For the nine months ended September 30, 2005, our average daily inlet volumes processed at the Enogex Wetumka Plant were 8,672 Mcf/d and approximately 796 Bbls/d of raw mix NGLs were produced, together with approximately 7,257 MMBtu/d of residue gas and 21 Bbls/d of condensate.
      The Twin Rivers System has approximately 256 active purchase and gathering contracts.
Mountain Systems
      Our three Mountain Systems are located in the Arkoma Basin and include Blue Mountain, Cyclone Mountain and Pine Mountain systems. These systems comprise a total of approximately 164 miles of pipeline ranging from two inches to 20 inches in diameter. These systems are located in Atoka, Pittsburg and Latimer counties, Oklahoma. Average throughput for the nine month period ended September 30, 2005 was 19,781 Mcf/d. As of September 30, 2005, there were approximately 136 active receipt meters connected to the Mountain gathering systems. Due to the lean nature of the wellhead production, natural gas gathered on our Mountain Systems does not require processing. Downstream pipeline interconnects include Blue Mountain, CenterPoint — East Zone, Cyclone Mountain — Enogex, NGPL-Texok, CenterPoint — East Zone and Pine Mountain — CenterPoint — East Zone.

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      The Mountain Systems have approximately 54 active gathering contracts, all of which are fee-based agreements.
Southern Dome, LLC
      As part of the ScissorTail Acquisition, we acquired a majority interest in Southern Dome, formed for the purpose of providing gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County and became its operator. Southern Dome is constructing a processing plant and pipelines to support anticipated future production in the Southern Dome area. Southern Dome has signed a 20-year gas purchase and processing agreement with the leading producer for our Mid-Continent Operations, New Dominion. Southern Dome has secured a 40-acre site for the plant, and is in the process of obtaining right-of -way permits. Construction of the plant, building, pipelines and compression are in progress. Our expected share of the construction cost of the project is anticipated to be $18.0 million. The processing plant and pipelines are expected to begin service during April 2006.
      We are required to make 100% of the capital contributions required by Southern Dome until such time as its capital account balance equals 73% of the aggregate capital account balances of us and the other members. The maximum amount of capital contributions that we are obligated to make to Southern Dome is $18.3 million. Additionally, prior to achievement of “payout,” we are entitled to receive 69.5% of member distributions and after achievement of “payout,” to 50.1% of member distributions. Payout is achieved once we have received distributions equal to its capital contributions plus a stated rate of return. We are the managing member of Southern Dome.
Mid-Continent Operations Natural Gas Supply
      We have pipelines and related assets in 21 counties in Oklahoma that have experienced increased levels of drilling activity from 2003 to 2004, which has led to increased volumes of natural gas through our Mid-Continent Operations pipeline systems. Based on discussions between us and producers in this area about their production plans, we expect to increase the volumes connected to these systems, providing us with opportunities to access newly developed natural gas supplies. We have not historically obtained independent evaluations of 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 precise estimates of total reserves dedicated to our Mid-Continent systems or the anticipated life of such producing reserves.
      Using the data derived from the study of productions trends completed by Energy Strategy Partners, we have constructed the following chart illustrating production trends from active wells adjacent to pipelines in our Mid-Continent Operations segment (within a ten-mile radius) from 1990 through August 31, 2005. Production levels are presented as average daily volumes stated in MMcf/d. The years shown inside the graph are the initial production years of the wells responsible for the shaded volumes of natural gas. The production

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amounts shown on this chart do not represent volumes of natural gas that flowed through our Mid-Continent Operations’ pipelines, but total production from active wells within the ten-mile radius described above.
PRODUCTION GRAPH
      During September 2005, our Mid-Continent Operations’ top producers by volume of natural gas were Altex Resources, Amvest, Chesapeake, New Dominion, and Special Energy, which collectively accounted for approximately 54% of the natural gas delivered to its natural gas gathering and intrastate pipeline systems.
      Our Mid-Continent Operations segment had 1,658 active receipt meters as of December 31, 2004 and added 34 receipt meters through September 30, 2005, more than offsetting the natural production decline of existing wells currently connected to its systems. Average wellhead production increased from 104,204 Mcf/d in 2003 to 112,372 Mcf/d during 2004, an increase of 7.4%. For the nine months ended September 30, 2005, average wellhead production was 125,529 Mcf/d as compared to 111,070 Mcf/d for the nine month period ended September 30, 2004, an increase of 13.0%. The greatest growth came from the Paden Plant area of the Stroud system, where, on average, production increased from 22,317 Mcf/d for the nine months ended September 30, 2004 as compared to 33,786 Mcf/d for the nine months ended September 30, 2005. The Stroud system is a current primary focus for expansion. The Hunton formation underlies virtually the entire Stroud system and is the primary reservoir being exploited across that system. Producers are utilizing horizontal well bores and dewatering techniques to economically access the gas entrained in the dolomite/limestone reservoir. As these drilling techniques applied to this formation have improved, the pace of drilling has increased significantly, with 52 wells drilled in the Stroud system in 2004 and 36 wells drilled during the nine months ended September 30, 2005.
      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 its 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. Our leading producer by volume has dedicated all of its existing and future production from property it leases within a 1.1 million acre area to ScissorTail pursuant to a contract that extends until 2020. We also have dedications from two additional producers covering existing and future production from a property leased by the producers within an aggregate of over 250,000 acres pursuant to contracts ending between 2009 and 2011.

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Competition in Our Mid-Continent Operating Region
      Competition for natural gas supplies in our Mid-Continent Operations’ region 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 natural gas gathering, transportation, compression, dehydration and processing.
      We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. 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 regions of operations.
      Prior to our acquisition of ScissorTail, it also made a significant investment in installing additional compression units, with many being new limited emissions multi-stage compressors. These compressors allow for quicker permitting and installation and also help us more efficiently provide the necessary pressure (at the inlet), providing us with an advantage over competitors without these capabilities. Additionally, substantially all of our systems offer low-pressure gathering service. The low pressure design of our systems allows for future system expansion as new wells are drilled and/or existing wells are re-completed.
      Our major competitors for natural gas supplies and markets in our Mid-Continent Operations’ region include CenterPoint, Duke Energy Field Services, Enogex and Enerfin.
Risk Management
      We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, 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 Prices
      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: (1) processing or conditioning at our processing plants or third-party processing plants and (2) purchasing and selling volumes of natural gas at index-related prices.
      The processing contracts in our Mid-Continent Operations segment are predominantly 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.
      The impacts of commodity prices on our Texas Gulf Coast Processing segment are more complex, involving the interplay between our contractual arrangements and the ability of our Houston Central Processing Plant to either process or condition gas depending on a price relationship known as the processing spread or processing margin. Under those arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under a significant number of these arrangements, we also charge producers and third-party transporters a conditioning fee. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs reduces the BTUs of the natural gas, and to replace these BTUs, we must purchase natural gas at

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market prices for return to producers or transporters. When NGL prices are high relative to natural gas prices, the processing margin is said to be positive, and we operate our Houston Central Processing Plant in a manner intended to extract NGLs to the fullest extent possible. Because of our contractual arrangements, operating our Houston Central Processing Plant in maximum recovery mode creates a long position in NGLs and a short position in natural gas. When processing margins are negative, we operate Houston Central Processing Plant in conditioning mode to extract the least amount of NGLs needed to meet downstream pipeline hydrocarbon dew point specifications. The ability to condition rather than fully process natural gas provides an operational hedge that allows us to reduce our commodity price exposure. Operating our Houston Central Processing Plant in conditioning mode creates positions in NGLs and natural gas that reduce our long or short commodity positions to relatively nominal levels in our Texas Gulf Coast segments.
      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 allows management to:
  •  purchase put options on West Texas Intermediate (“WTI”) crude oil;
 
  •  purchase put or call options and collars (purchase of a put together with the sale of a call) and/or sell fixed for floating swaps on natural gas at Henry Hub, Houston Ship Channel or other highly liquid points relevant to our operations; and
 
  •  purchase put options and collars (purchase of a put together with the sale of a call) and/or sell fixed for floating swaps on natural gas liquids to which we, or an entity to be acquired by us, have direct price exposure, priced at Mt. Belvieu or Conway.
      The 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 or natural gas liquids hedge instruments must be limited to three years from the date of the transaction;
 
  •  maturities with respect to the purchase of any natural gas hedge instruments must be limited to four years from the date of the transaction;
 
  •  notional volume must not exceed (i) 60% of the projected requirements or output, as applicable, for the hedged period with respect to the purchase of crude oil or natural gas liquids put options, and (ii) 80% of the projected requirements or output, as applicable, for the hedged period with respect to the purchase of natural gas put or call 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 and Standard & Poor’s 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 or exceed the requirements for effective hedges as outlined in SFAS No. 133, “ Accounting for Derivative Instruments and Hedging Activities .”

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      Mid-Continent Operations Segment. Natural gas for our Mid-Continent Operations segment is hedged using the CenterPoint East index, the principal index used to price the underlying commodity. With the exception of natural gasoline and condensate, NGLs are contractually priced using the Conway index, but since there is an extremely limited forward market for Conway, we use Mt. Belvieu hedge instruments instead. While this creates the potential for basis risk, statistical analysis reveals that the two indices are highly correlated. When the basis differential widens between the two, the Conway index is frequently higher which would benefit us under this hedge strategy.
      Texas Gulf Coast Pipelines and Processing Segments. With the exception of natural gasoline and condensate, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. We do not hedge natural gas for the Texas Gulf Coast Pipelines and Processing segments because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central Processing Plant to switch between full recovery and conditioning mode. Because of our ability to reject ethane, we have not hedged our ethane production from our Texas Gulf Coast Processing segment.
      The following table summarizes our commodity hedge portfolio as of December 29, 2005 (all hedges are settled monthly):
Purchased Centerpoint East Natural Gas Puts
                                 
    Put Strike   Put Volumes        
    (Per MMbtu)   MMbtu/d        
                 
2006
  $ 9.90       7,750                  
2007
  $ 8.75       9,750                  
2008
  $ 7.75       5,000                  
2009
  $ 6.95       5,000                  
Purchased Purity Ethane Puts and entered into swaps as listed below:
                                 
    Put Strike   Put Volumes   Swap price   Swap Volumes
    (per gallon)   Bbls/d   (per gallon)   Bbls/d
                 
2006
  $ 0.7125       568     $ 0.7315       568  
2007
  $ 0.6365       599     $ 0.6525       599  
2008
  $ 0.5700       607     $ 0.5650       607  
Purchased TET Propane Puts and entered into swaps as listed below:
                                 
    Put Strike   Put Volumes   Swap price   Swap Volumes
    (per gallon)   Bbls/d   (per gallon)   Bbls/d
                 
2006
  $ 0.9525       2,508     $ 1.0000       659  
2007
  $ 0.8930       2,575     $ 0.9375       726  
2008
  $ 0.8360       2,594     $ 0.8700       745  
Purchased Non-TET Iso-Butane Puts and entered into swaps as listed below:
                                 
    Put Strike   Put Volumes   Swap price   Swap Volumes
    (per gallon)   Bbls/d   (per gallon)   Bbls/d
                 
2006
  $ 1.1425       613     $ 1.2050       83  
2007
  $ 1.0675       620     $ 1.1250       90  
2008
  $ 0.9900       622     $ 1.0450       92  

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Purchased Non-TET Normal-Butane Puts and entered into swaps as listed below:
                                 
    Put Strike   Put Volumes   Swap price   Swap Volumes
    (per gallon)   Bbls/d   (per gallon)   Bbls/d
                 
2006
  $ 1.1400       780     $ 1.2000       241  
2007
  $ 1.0650       803     $ 1.1200       264  
2008
  $ 0.9875       810     $ 1.0400       271  
Purchased WTI Crude Oil Puts as listed below:(1)
                 
    Put Strike   Put Volumes
    (per barrel)   Bbls/d
         
2006
  $ 48.00       2,000  
2007
  $ 48.00       2,000  
 
(1)  WTI Crude Oil Puts were purchased in July 2005. Volumes are based on a 30-day month.
Interest Rates
      Our interest rate exposure results from variable rate borrowings under our debt agreements. As of the quarter ended September 30, 2005, we were exposed to changes in interest rates as a result of the indebtedness outstanding under our credit facilities of $402.0 million, which had an average floating interest rate of 7.1%. A 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $4.0 million annually.
      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 most senior credit agreement. In October 2005, we entered into two interest rate swap agreements with an aggregate notional amount of $50 million in which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the senior secured revolving credit facility for fixed rate interest. We have designated these two interest rate swaps as cash flow hedges under SFAS No. 133. Under each swap agreement, we pay the counterparties the fixed interest rate of approximately 4.7% monthly and receive in return a variable interest rate based on one-month LIBOR rates. The interest rate swaps cover the period from October 2005 through July 2010 and the settlement amounts will be recognized to earnings as either an increase or a 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 senior level executives in the operations, finance and legal departments. The Audit Committee of our Board of Directors monitors the implementation of the policy, and we have engaged an independent firm to provide additional oversight.
Credit Risk and Significant Customers
      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 the 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 nine months ended September 30, 2005, Oneok Hydrocarbons, L.P., Kinder Morgan Texas Pipeline, L.P., and a subsidiary of Dow Chemical collectively accounted for approximately 58% of our pro forma revenue.

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Regulation
      Regulation by the FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or 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 extension or abandonment of services and facilities;
 
  •  the maintenance of accounts and records;
 
  •  the acquisition and disposition of facilities;
 
  •  the initiation and discontinuation of services; and
 
  •  various other matters.
      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. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation. As a result, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.
      Intrastate Pipeline Regulation. Our intrastate natural gas pipeline operations generally are not subject to rate regulation by the FERC, but they are subject to regulation by the State of Texas. Likewise, the intrastate natural gas pipeline facilities acquired in the ScissorTail Acquisition are subject to regulation by the State of Oklahoma. However, 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 the FERC jurisdiction under Section 311 of the Natural Gas Policy Act, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline.
      Some of our operations in Texas are subject to the Texas Gas Utility Regulatory Act, as implemented by the Railroad Commission of Texas, or the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates.
      Some of the operations acquired under the ScissorTail Acquisition are subject to the Oklahoma Corporate Commission, or the OCC regulation as public utilities. Generally, the OCC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates charged by these assets in Oklahoma are deemed just and reasonable under Oklahoma law unless challenged in a complaint. We cannot predict whether such complaint will be filed against us or whether the OCC will change its regulation of these rates.
      Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. We own a number of intrastate natural gas pipelines in Texas that we believe would meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. We also believe that the pipeline facilities to be acquired in the ScissorTail Acquisition meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, 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 determinations by FERC and the courts. State

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regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
      We are currently subject to state ratable take and common purchaser statutes in Texas, and are also subject to state ratable take and common purchaser statutes in Oklahoma as a result of the ScissorTail Acquisition. The 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 undue discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.
      Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. 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.
      Sales of Natural Gas. 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. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.
Environmental Matters
      The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids 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 our wastes;
 
  •  limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
 
  •  requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operators; and
 
  •  enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

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      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 substances or 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.
      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 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. Nevertheless, the trend in environmental 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 discussion of certain environmental, health and safety laws and regulations that relate to our operations.
      Hazardous Waste. Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended, or 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 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 less stringent 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 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, or 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 as well as natural gas is 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. 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 the 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 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.

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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 strictly 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 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 of 1972, 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 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 an appropriately issued permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations.
      Pipeline Safety. Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, 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 (LNG) and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, 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 existing NGPSA 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 could result in increased costs.
      The DOT, through the Office of Pipeline Safety, recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. Similar rules are already in place for operators of hazardous liquid pipelines. The Texas Railroad Commission, or TRRC and the Oklahoma Corporation Commission or OCC, have adopted similar regulations applicable to intrastate gathering and transmission lines. Compliance with these existing rules has not had a material adverse effect on our operations but there is no assurance that this trend will continue in the future.
      Employee Health and Safety. We are subject to the requirements of the Occupational Safety and Health Act, as amended, referred to as 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 information be

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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.
Office Facilities
      We occupy approximately 15,500 square feet of space at our executive offices in Houston, Texas under a lease expiring on May 12, 2012 and are in the process of adding an additional 15,500 square feet of office space under this lease. At the expiration of the primary term, we have an option to renew this lease for an additional five years at the 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 ScissorTail subsidiary. The Tulsa lease is for a five-year term and provides us with a five-year renewal option at then prevailing market rates. We additionally lease certain of our field office facilities. Certain of our owned office facilities are located on land leased by us or on land subject to a permanent easement. 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 September 30, 2005, we, through our subsidiaries, CPNO Services, L.P. and ScissorTail, had 180 full-time employees and 3 part-time employees and Copano Operations employed 13 full time employees and one part-time employee on our behalf. None of our employees are covered by collective bargaining agreements. We consider our relations with these employees, with Copano/Operations, Inc. (“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 will be dedicated to provide services on our behalf, we refer to them as our employees. Please read “Certain Relationships and Related Transactions — Copano/ Operations, Inc.”
Properties
      Substantially all of our pipelines are constructed on rights-of -way granted by the apparent record owners of the property. 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.
      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 all of 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.
Litigation
      Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. 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.

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MANAGEMENT
      The following table shows information for our executive and operating officers and members of our board of directors. Executive officers and directors are elected for one-year terms.
                     
Name   Age   Position with Our Company   Director Since
             
John R. Eckel, Jr. 
    54     Chairman of the Board and Chief Executive Officer     1992  
R. Bruce Northcutt
    46     President and Chief Operating Officer        
Matthew J. Assiff
    38     Senior Vice President and Chief Financial Officer        
Ron W. Bopp
    59     Senior Vice President, Corporate Development        
Lari Paradee
    42     Vice President and Controller        
Douglas L. Lawing
    44     Vice President, General Counsel and Secretary        
Kathryn S. DeYoung
    45     Vice President, Government and Regulatory Affairs        
Wayne S. Harrison
    56     Vice President and Chief Information Officer        
Texas Gulf Coast
                   
Brian D. Eckhart
    50     Senior Vice President, Transportation and Supply        
J. Terrell White
    41     Vice President, Operations        
James J. Gibson, III
    59     Vice President, Processing        
Mid-Continent Operations
                   
John R. Raber
    51     President and Chief Operating Officer        
Lee A. Fiegener
    46     Vice President, Operations        
Thomas A. Coleman
    49     Vice President, Engineering        
Bruce A. Roderick
    47     Vice President, Accounting and Administration        
Sharon J. Robinson
    46     Vice President Commercial Activities        
Non-Executive Board Members
                   
Robert L. Cabes, Jr. 
    36     Director     2001  
James G. Crump
    65     Director     2004  
Ernie L. Danner
    51     Director     2004  
Scott A. Griffiths
    51     Director     2004  
Michael L. Johnson
    55     Director     2004  
T. William Porter
    64     Director     2004  
William L. Thacker
    60     Director     2004  
      John R. Eckel, Jr. founded our business in 1992 and served as our President and Chief Executive Officer until April 2003, when he was elected to his current position of Chairman of the Board and Chief Executive Officer. Mr. Eckel serves on the Board of Directors and as Vice Chairman of the Texas Pipeline Association. Mr. Eckel also serves as President and Chief Executive Officer of Live Oak Reserves, Inc., which he founded in 1986, and which, with its affiliates, is engaged in oil and gas exploration and production in South Texas. Mr. Eckel received a Bachelor of Arts degree from Columbia University and was employed in various corporate finance positions in New York prior to entering the energy industry in 1979.
      R.     Bruce Northcutt, President and Chief Operating Officer, has served in his current capacity since April 2003. Mr. Northcutt served as President of El Paso Global Networks Company (a provider of wholesale bandwidth transport services) from November 2001 until April 2003, Managing Director of El Paso Global Networks Company from April 1999 until December 2001 and Vice President, Business Development, of El Paso Gas Services Company (a marketer of strategic interstate pipeline capacity) from January 1998 until

103


 

April 1999. Mr. Northcutt began his career with Tenneco Oil Exploration and Production in 1982 working in the areas of drilling and production engineering. From 1988 until 1998, Mr. Northcutt held various levels of responsibility within several business units of El Paso Energy and its predecessor, Tenneco Energy, including supervision of pipeline supply and marketing as well as regulatory functions. Mr. Northcutt holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. Mr. Northcutt is a Registered Professional Engineer in Texas.
      Matthew J. Assiff, Senior Vice President and Chief Financial Officer, has served in his current capacity since October 2004 and previously served as our Senior Vice President, Finance and Administration, since January 2002. Prior thereto, Mr. Assiff was a Vice President within the Global Energy Group of Credit Suisse and was with Donaldson, Lufkin and Jenrette (prior to its purchase by Credit Suisse in 2000) initially as an Associate and subsequently as a Vice President from 1998. Mr. Assiff began his career in 1989 with Goldman, Sachs & Co. in the Merger & Acquisitions group focusing on energy transactions and has worked in the corporate finance and Merger & Acquisition groups of Bear Stearns and Chemical Securities (now J. P. Morgan Chase). Mr. Assiff has also worked with Landmark Graphics Company and Compaq Computer in the areas of finance, planning, mergers and acquisitions and corporate venture investing. Mr. Assiff graduated from Columbia University with a Bachelor of Arts degree and holds a Masters of Business Administration degree from Harvard Business School.
      Ron W. Bopp, Senior Vice President, Corporate Development, was elected to his current position in April 2005 to assist us with the development and management of our acquisition opportunities. Mr. Bopp served as Vice President  — Onshore Assets of Shell US Gas & Power LLC, an affiliate of Shell Oil Company, from February 1998 until February 2005. From 1994 until February 1998, Mr. Bopp was Vice President and Chief Financial Officer of Corpus Christi Natural Gas Company, a midstream gas gathering, processing, and transportation company that was acquired by affiliates of Shell Oil Company in October 1997. Mr. Bopp graduated from the University of Houston with a Bachelor of Business Administration and a Master of Science in Accounting degree and is a Certified Public Accountant.
      Lari Paradee, Vice President and Controller, has served in her current capacity since joining us in July 2003. As Vice President and Controller, Ms. Paradee is primarily responsible for our accounting and reporting functions. From September 2000 until March 2003, Ms. Paradee served as Accounting and Consolidations Manager for Intergen, a global power generation company jointly owned by Shell Generating (Holdings) B.V. and Bechtel Enterprises Energy B.V. Ms. Paradee served as Vice President and Controller of DeepTech International, Inc. (an offshore pipeline and exploration and production company) from May 1991 until August 1998, when DeepTech was merged into El Paso Energy Corporation. Ms. Paradee then served as Manager, Finance and Administration of El Paso Energy until March 2000. Ms. Paradee has served as Senior Auditor and Staff Auditor for Price Waterhouse. Ms. Paradee graduated magna cum laude from Texas Tech University with a B.B.A. in Accounting. Ms. Paradee is also a Certified Public Accountant.
      Douglas L. Lawing, Vice President, General Counsel and Secretary, has served in his current capacity since October 2004 and previously served as our General Counsel since November 2003. From January 2002 until November 2003, Mr. Lawing served as our Corporate Counsel. Since February 1994, Mr. Lawing has served as corporate secretary of our company and its predecessors. Additionally, from March 1998 until January 2002, Mr. Lawing served as an Associate Counsel of Nabors Industries, Inc. (now Nabors Industries Ltd., a land drilling contractor). Mr. Lawing holds a Bachelor of Science degree in Business Administration from the University of North Carolina at Chapel Hill and a J.D. from Washington and Lee University.
      Kathryn S. DeYoung, Vice President, Government and Regulatory Affairs, has served in her current capacity since March 1, 2005. Ms. DeYoung is responsible for coordinating government affairs activities and compliance with state and federal regulations, including compliance with environmental, health and safety standards. Ms. DeYoung has been associated with us since our inception in 1992 and from August 2001 through February 2005, Ms. DeYoung served as our Senior Director, Operations Services and from June 1992 until August 2001, she served as our Director of Operations Services where her duties included regulatory compliance and risk management. Ms. DeYoung attended the University of St. Thomas and the University of Houston.

104


 

      Wayne S. Harrison, Vice President and Chief Information Officer, has served in his current capacity since joining Copano in June 2005. From Copano’s inception in 1992 until June 2005, Mr. Harrison served as a consultant to Copano and in that capacity, developed and supported various accounting and financial software application systems. During this period, Mr. Harrison provided similar services to a number of other entities, including Tejas Gas, Energy Dynamics, and O’Connor-Braman Interests and also served as IT Manager for Berry Contracting from 1992 until May 2005. Mr. Harrison graduated from Del Mar College in Corpus Christi, Texas, with an Associate of Applied Science degree in Computer Science and attended Texas A&M University-Corpus Christi.
      Brian D. Eckhart, Senior Vice President, Transportation and Supply, has served in his current capacity since March 2002. From January 1998 until March 2002, Mr. Eckhart served as our Vice President, Business Development. From February 1997 to January 1998, Mr. Eckhart served as Vice President, Operations. From 1979 until 1997, Mr. Eckhart held various engineering and management positions at Natural Gas Pipeline Company of America and other subsidiaries of MidCon Corporation, a predecessor of Kinder Morgan, Inc. Mr. Eckhart graduated from Texas A&M University with a Bachelor of Science degree in Ocean Engineering.
      J. Terrell White, Vice President, Operations, has served in his current capacity since joining us in January 1998. Mr. White oversees pipeline operations, including new well connects, dehydration, compression, measurement, and construction activities. From 1990 until 1997, Mr. White served in increasingly responsible engineering, project management and business development roles with Enron Liquid Services Corp., and from February 1997 until January 1998 with TransCanada Energy USA, Inc., following its acquisition of certain Enron midstream assets. From 1985 until 1990, Mr. White was an engineer with Mobil E&P SE, Inc. and Mobil Chemical, involved primarily in gas processing, fractionation, gathering and NGL transportation. Mr. White is a registered professional engineer in the State of Oklahoma. Mr. White graduated from the University of Alabama with a Bachelor of Science degree in Mechanical Engineering.
      James J. Gibson, III, Vice President, Processing, has served in his current capacity since joining us in October 2001. Mr. Gibson oversees operations for our processing segment. From 1998 until September 2001, Mr. Gibson served as Manager, Business Development — Texas Gas Plants of Coral Energy, LLC, an affiliate of Shell Oil Company. From 1997 until 1998, Mr. Gibson served as Director, Gas Processing and Treating Services of Corpus Christi Natural Gas, Inc. From 1992 until 1997, Mr. Gibson was self-employed as a consultant to several midstream energy companies operating in Texas. From 1980 until 1992, Mr. Gibson served as Vice President — Plant Operations of Seagull Energy Corporation. From 1977 until 1980, Mr. Gibson served as project engineer for Houston Oil & Minerals Corporation. Mr. Gibson began his career in 1969 as an engineer with Sun Oil Company. Mr. Gibson is a registered professional engineer in the State of Texas. Mr. Gibson graduated from Texas A&I University with a Bachelor of Science degree in Natural Gas Engineering.
      John A. Raber, President and COO — ScissorTail Energy, LLC, has served in his current capacity since ScissorTail was formed on July 1, 2000. Mr. Raber was also Named President and COO — Copano Rocky Mountains and Mid-Continent, LLC on August 1, 2005. Mr. Raber served as Vice President of Marketing and Business Development of Wyoming Refining Company (a Rocky Mountains refiner) from July 1999 to August 2005, Sr. Vice President of Processing and other executive positions with Tejas Gas Corporation (a public midstream company) from February 1995 to July 1999 and as Vice President and other positions with LEDCO, Inc. (a private midstream and gas distribution company in Louisiana) from July 1982 to February 1995. Mr. Raber began his career as a Field and Operations Engineer with J. Ray McDermott, Inc. (a marine oil and gas construction company) working in mainly overseas locations from May 1976 to July 1982. Mr. Raber holds a Bachelor of Science in Civil Engineering from Tulane University and has also attended the Stanford Business School of Executive Education.
      Lee R. Fiegener, Vice President, Field Operations — ScissorTail Energy, LLC, has served in his current capacity since July 2002. Mr. Fiegener joined ScissorTail Energy when it was formed and served as General Manager from July 2000 to July 2002. Prior to joining Scissortail Energy, Mr. Fiegener served as District Manager for Enogex Inc., (a public midstream gathering, processing, and transmission company), from July 1999 to July 2000, and as Regional Manager and other positions with Transok, LLC (a public midstream

105


 

gathering, processing and transmission company), from Aug 1982 to July 1999. Mr. Fiegener began his career with Transok in Aug. 1982 as an Engine/ Vibration Analyst. Mr. Fiegener holds a Bachelor of Science in Mechanical Engineering Technology from Oklahoma State University.
      Thomas A. Coleman, Vice President, Engineering — ScissorTail Energy, LLC, joined the company in September of 2000 as Manager of Engineering and was named Vice President in August, 2005. Prior to ScissorTail, Mr. Coleman was a senior design engineer and project manager at Transok (a public midstream company) from July 1993 to December 1999. Mr. Coleman was employed at Willbros Engineers (pipeline consulting company) from March 1989 to July 1993 and December 1999 to September 2000 as a project scheduler, field engineer and lead design engineer. Mr. Coleman began his career at Public Service Company of Oklahoma (electric utility company) and worked from 1982 to 1989 as a power plant performance engineer. Mr. Coleman earned a Bachelor of Science in Mechanical Engineering from the University of Tulsa in 1982 and is a registered professional engineer.
      Bruce A. Roderick, Vice President, Accounting and Administration — Scissortail Energy, LLC has served in his current capacity since ScissorTail was formed on July 1, 2000. Mr. Roderick served as Vice President, Accounting and Administration and other positions of Transok, LLC (a public midstream company) from April 1997 to September 1999. Mr. Roderick served as Director, Power Marketing for Central and Southwest Corporation (a public utility holding company) from March 1996 to April 1997. Mr. Roderick served Transok, LLC from February 1987 to March 1996 in leadership roles over Information Technology, Strategic Planning, Gas and Volume Control and Fuel Acquisition. Mr. Roderick began his career as a information technology consultant with Arthur Young & Company (a public accounting firm) from May 1980 to February 1987. Mr. Roderick holds a Bachelor of Science degree in Accounting from Oklahoma State University and is a Certified Public Accountant.
      Sharon J. Robinson, Vice President, Commercial Activities — ScissorTail Energy, LLC, has served in her current capacity since June 2003. Ms. Robinson is responsible for overseeing the commercial operations, budgeting and business development activities for Scissortail. Ms. Robinson joined ScissorTail when it was formed on July 1, 2000 and served as General Manager, Commercial from September 2001 to June 2003. Ms. Robinson worked for Transok, LLC (a public midstream) which later became Tejas Gas Corporation from July 1993 through December 1999 in both commercial and engineering positions. Ms. Robinson began her career as a Project Engineer with Cities Service Oil Company, which later became Occidental Petroleum in December 1981 and continued through March 1992. Ms. Robinson holds a Bachelor of Science in Chemical Engineering from Oklahoma State University and is a registered professional engineer.
      Robert L. Cabes, Jr. joined our Board of Directors in 2001. Since 2005, he has been a Principal of Avista Capital Holdings, L.P. a private equity firm focused on investments in the energy, media and healthcare sectors. Mr. Cabes was engaged by Credit Suisse’s Alternative Capital Division as a consultant in 2005. As a consultant to Credit Suisse, he continues to serve on the boards of and monitor the operations of various portfolio companies of Credit Suisse’s Alternative Capital Division. Previously, Mr. Cabes was a Principal of Global Energy Partners, a specialty group within Credit Suisse’s Alternative Capital Division that makes investments in energy companies. Prior to joining Global energy Partners in 2001, he was with the Investment Banking Division of Credit Suisse First Boston beginning in 2000. Mr. Cabes serves as a director of Pinnacle Gas Resources, Inc. He holds a B.B.A from Southern Methodist University and is a CFA charterholder.
      James G. Crump joined our Board of Directors upon completion of our initial public offering in November 2004. Mr. Crump is the Chairman of the Audit Committee and a member of the Conflicts Committee. He began his career at Price Waterhouse in 1962 and became a partner in 1974. From 1977 until the merger of Price Waterhouse and Coopers & Lybrand in 1998, Mr. Crump held numerous management and leadership roles. From 1998 until his retirement in 2001, Mr. Crump served as Global Energy and Mining Cluster Leader, a member of the U.S. Management Committee and the Global Management Committee and as Houston Office Managing Partner of PricewaterhouseCoopers. Mr. Crump holds a B.A. in Accounting from Lamar University.

106


 

INDEX TO FINANCIAL INFORMATION
       
    Page
     
 
ScissorTail Energy, LLC and Subsidiary Consolidated Financial Statements:
   
 
Unaudited Consolidated Balance Sheets — June 30, 2005 and December 31, 2004
  F-74
 
Unaudited Consolidated Statements of Operations for the Six Months Ended June 30, 2005 and 2004
  F-75
 
Unaudited Consolidated Statement of Members’ Equity and Comprehensive Income for the Six Months Ended June 30, 2005
  F-76
 
Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004
  F-77
 
Notes to Unaudited Consolidated Financial Statements
  F-78

F-1


 

ScissorTail Energy, LLC
CONSOLIDATED BALANCE SHEETS
                     
    June 30,   December 31,
    2005   2004
         
    (unaudited)
ASSETS
CURRENT ASSETS:
               
 
Cash and cash equivalents
  $ 16,850,983     $ 9,720,088  
 
Accounts receivable
    26,290,087       25,227,934  
 
Prepaid expenses and other
    301,491       561,037  
 
Derivative assets
    874,703       1,037,284  
             
   
Total current assets
    44,317,264       36,546,343  
             
PROPERTY, PLANT AND EQUIPMENT, at cost:
               
 
Land and rights-of-way
    4,797,150       4,777,180  
 
Natural gas processing plant
    15,465,842       15,093,932  
 
Pipelines and pipeline equipment
    39,593,471       40,584,490  
 
Compressors
    16,143,699       15,587,784  
 
Corporate and other
    1,136,794       1,105,761  
 
Construction-in-progress
    8,292,817       4,668,349  
             
      85,429,773       81,817,496  
   
Less-accumulated depreciation
    (10,162,126 )     (8,513,328 )
             
   
Net property, plant and equipment
    75,267,647       73,304,168  
             
OTHER ASSETS:
               
 
Gas purchase contract, net of accumulated amortization of $4,428,214 and $3,990,546 at June 30, and December 31,2004, respectively
    1,604,785       2,042,454  
Loan origination fees, net of accumulated amortization of $212,173 and $157,521 at June 30, 2005 and December 31, 2004, respectively
    100,194       154,845  
Other
    1,843,955       1,555,646  
             
   
Total other assets
    3,548,934       3,752,945  
             
   
Total assets
  $ 123,133,845     $ 113,603,456  
             
 
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
               
 
Gas purchases payable
  $ 31,487,086     $ 28,265,596  
 
Accounts payable
               
   
Trade
    1,082,428       3,024,437  
   
Due to affiliate
    45,125       17,504  
 
Accrued liabilities
    2,062,672       2,807,407  
 
Derivative liabilities
    912,490       521,255  
             
   
Total current liabilities
    35,589,801       34,636,199  
             
COMMITMENTS AND CONTINGENCIES
               
MEMBERS’ EQUITY:
               
 
Members’ equity
    87,581,831       78,451,228  
 
Accumulated other comprehensive income (loss)
    (37,787 )     516,029  
             
   
Total members’ equity
    87,544,044       78,967,257  
             
   
Total liabilities and members’ equity
  $ 123,133,845     $ 113,603,456  
             
The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-74


 

ScissorTail Energy, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
                     
    Six Months   Six Months
    Ended   Ended
    June 30,   June 30,
    2005   2004
         
    (unaudited)
REVENUES
  $ 154,446,325     $ 110,826,265  
OPERATING COSTS AND EXPENSES:
               
 
Natural gas purchases and gas transportation costs
    122,427,788       90,656,964  
 
System operating and maintenance expenses
    6,289,644       5,520,758  
 
General and administrative expenses
    1,690,216       1,730,368  
 
Depreciation and amortization
    2,141,175       2,005,185  
             
   
Total operating costs and expenses
    132,548,823       99,913,275  
             
OPERATING INCOME
    21,897,502       10,912,990  
OTHER INCOME (EXPENSE):
               
 
Interest expense
    (41,523 )     (453,593 )
 
Interest income and other
    178,371       67,782  
             
NET INCOME
  $ 22,034,350     $ 10,527,179  
             
The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-75


 

ScissorTail Energy, LLC
CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY AND COMPREHENSIVE INCOME
For the six months ended June 30, 2005
                             
        Accumulated    
        Other    
    Members’   Comprehensive    
    Equity   Income (Loss)   Total
             
    (unaudited)
BALANCE, December 31, 2004
  $ 78,451,228     $ 516,029     $ 78,967,257  
DISTRIBUTIONS TO MEMBERS
    (12,903,747 )           (12,903,747 )
COMPREHENSIVE INCOME:
                       
 
Net income
    22,034,350             22,034,350  
 
Current period change in derivative instruments
          (553,816 )     (553,816 )
                   
   
Total comprehensive income
                    21,480,534  
                   
BALANCE, June 30, 2005
  $ 87,581,831     $ (37,787 )   $ 87,544,044  
                   
The accompanying notes are an integral part of this unaudited consolidated financial statement.

F-76


 

ScissorTail Energy, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
                         
    June 30,   June 30,
    2005   2004
         
    (unaudited)
OPERATING ACTIVITIES:
               
 
Net income
  $ 22,034,350     $ 10,527,179  
 
Adjustments to reconcile net income to net cash provided by operating activities
               
   
Depreciation and amortization
    2,141,175       2,005,185  
   
Gain on sale of assets
    (3,356 )     (48,666 )
   
Non-cash interest on notes due to affiliates
          222,955  
   
Changes in operating assets and liabilities
               
     
Accounts receivable
    (1,062,154 )     (3,327,140 )
     
Prepaid expenses and other
    259,546       355,206  
     
Other assets
    (288,308 )     (291,336 )
     
Gas purchases payable
    3,221,490       7,246,162  
     
Accounts payable
    (1,914,388 )     (192,077 )
     
Accrued liabilities
    (744,735 )     (470,225 )
             
       
Net cash provided by operating activities
    23,643,620       16,027,243  
             
INVESTING ACTIVITIES:
               
 
Purchase of property, plant and equipment
    (3,612,777 )     (3,038,660 )
 
Proceeds from dispositions of property, plant and equipment
    3,800       97,324  
             
       
Net cash used in investing activities
    (3,608,977 )     (2,941,336 )
             
FINANCING ACTIVITIES:
               
 
Proceeds from borrowings
    845,798        
 
Payments on borrowings
    (845,798 )     (6,795,382 )
 
Distributions to members
    (12,903,748 )     (3,100,000 )
             
       
Net cash used in financing activities
    (12,903,748 )     (9,895,382 )
             
INCREASE IN CASH AND CASH EQUIVALENTS
    7,130,895       3,190,525  
CASH AND CASH EQUIVALENTS, beginning of period
    9,720,088       8,782,561  
             
CASH AND CASH EQUIVALENTS, end of period
  $ 16,850,983     $ 11,973,086  
             
SUPPLEMENTAL INFORMATION:
               
 
Cash paid for interest
  $ 54,594     $ 230,638  
             
The accompanying notes are an integral part of these unaudited consolidated financial statements.

F-77


 

ScissorTail Energy, LLC
Notes to consolidated financial statements
(unaudited)
A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ORGANIZATION
1. Organization
      ScissorTail Energy, LLC (the Company), a limited liability company, was organized June 29, 2000 under the laws of the state of Delaware. The Company primarily gathers and processes natural gas in Oklahoma. In January 2005, the Company formed Southern Dome, LLC (Southern Dome), a limited liability company, organized under the laws of the state of Delaware and a wholly-owned subsidiary of the Company. Southern Dome had no activity for the period ended June 30, 2005.
      On August 1, 2005, Houston-based Copano Energy, LLC acquired the Company for $495.6 million in cash, which reflected estimated net working capital adjustments.
      In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of ScissorTail Energy, LLC and subsidiary as of June 30, 2005, and the results of operations for the six-month periods ended June 30, 2005 and 2004. The unaudited interim consolidated financial statements should be read in conjunction with the financial statements and notes thereto of ScissorTail Energy, LLC for the year ended December 31, 2004.
2. Use of Estimates
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.
3. Derivatives and Hedging
      The Company applies the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, to its derivatives and hedging activities. The fair value of all derivative assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The amount on the balance sheet relating to derivative assets and liabilities in accumulated other comprehensive income will be reclassified into earnings when the transactions being hedged occur.
      In 2004, the Company entered into certain natural gas derivative transactions on its account. These contracts consist of calls, puts and collars and represent cash flow hedges that were executed in order to hedge the Company’s exposure to changes in the price of natural gas. The Company has a formal policy for any hedge transaction which limits the open position to no more than 9,000 MMBtu per day in any one month. At June 30, 2005, the summary of the Company’s derivative contracts for its account is as follows: Collars for 200,000 MMBtu per month for the period July 2005 through October 2005 at prices ranging from $5.00 to $8.01. At December 31, 2004, the summary of the Company’s contracts is as follows: Collars for 100,000 to 250,000 MMBtu per month for the period January 2005 through October 2005 at prices ranging from $5.00 to $9.00.
      In 2004 and 2005, the Company entered into certain derivative transactions on behalf of three major suppliers from whom the Company purchases a significant volume of natural gas. The arrangement with the suppliers provides that any gains or losses that result from the derivative transactions pass through to the suppliers. The Company evaluates the credit risk related to the suppliers on a regular basis, and the Company received a fee up to $1,500 per month related to these transactions. The Company had approximately $106,000 due to suppliers at June 30, 2005, included in gas payables, in the accompanying balance sheet. In July 2005, the Company paid $96,000 to settle all of its derivative instruments outstanding at June 30, 2005.

F-78


 

ScissorTail Energy, LLC
Notes to consolidated financial statements — (Continued)
4. Accumulated Other Comprehensive Income (Loss)
      The reconciliation of accumulated other comprehensive income (loss) for the period ended March 31, 2005, is as follows:
         
Balance, beginning of period
  $ 516,029  
Current period reclassification to earnings
    102,000  
Current period change in unrealized gain (loss) from derivatives
    (655,816 )
       
Balance, end of period
  $ (37,787 )
       
B — LONG-TERM DEBT
      The Company had a loan and security agreement (the Credit Facility) with a commercial bank that provided for a $15,000,000 revolving loan. As collateral for the Credit Facility, the Company pledged substantially all of its assets.
      The amount that the Company could borrow under the revolving loan was limited, at any given time, to the borrowing base as determined by eligible accounts receivable. For each advance, the Company designated the interest terms by selecting either a prime rate revolving loan or a LIBOR revolving loan (both defined in the Credit Facility). Interest payments were due monthly. The outstanding principal and all accrued interest on the revolving loan were due and payable May 29, 2006. The Company had no outstanding borrowings under the revolving loan at June 30, 2005. The amount available under this credit facility at June 30, 2005 was $15 million. The credit facility was terminated in August 2005.
C — COMMITMENTS AND CONTINGENCIES
      The Company enters into natural gas purchase and sales contracts and natural gas processing agreements in the ordinary course of its gas gathering and processing business.
      Under the provisions of a natural gas liquids sales agreement with one of the Company’s major customers, the Company is subject to incremental transportation charges if the delivered volumes of liquids are less than a specified minimum volume. Through June 30, 2005, the volumes delivered were less than the specified minimum. As a result, the Company has accrued an obligation of approximately $453,000 at June 30, 2005, which management believes adequately reflects the obligation at that date.
      Certain key employees of the Company have profit participation agreements that provide for cash payments in the event of a change of control of ScissorTail. Any profit participation amount payable under these agreements would be based on the employee’s profit percentage multiplied by the net proceeds of the transaction giving rise to a change of control. For purposes of these agreements, a change of control occurs when the members, ScissorTail Holdings, LLC and Hamilton ScissorTail LLC, taken together, no longer own or control at least 50% of the membership interests in ScissorTail Energy, LLC. As a result of the sale of the Company to Copano in August 2005, approximately $13,567,000 was paid to these employees from the proceeds of the sale.
      The Company has a change of control agreement with a key employee that provides for a cash payment in the event of a change in control in which the employee is not retained by the Company subsequent to the change in control. As a result of the sale of the Company, approximately $2 million was paid to the employee in August 2005.

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BROKERAGE PARTNERS