**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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**Form 10-Q**

**x**                              Quarterlyreport pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**Forthe quarterly period ended September 30, 2005**

**OR**

**o**                                 Transitionreport pursuant to Section 13 or 15(d) of the Securities Exchange Actof 1934

**Commissionfile number: 001-32329**

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**Copano Energy, L.L.C.**

(Exact Name of Registrantas Specified in Its Charter)

| **Delaware**                     |   | **51-0411678**       |
|----------------------------------|--------|----------------------|
| (State or Other  Jurisdiction of |   | (I.R.S. Employer     |
| Incorporation or  Organization)  |   | Identification  No.) |

 

**2727 Allen Parkway,Suite 1200**

**Houston, Texas 77019**

(Address of PrincipalExecutive Offices)

**(713) 621-9547**

(Registrant’s TelephoneNumber, Including Area Code)

Indicate by check mark whetherthe registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days. Yes  x  No  o

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Exchange Act). Yes  o  No  x

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act). o  Yes  x  No

Therewere 13,378,938 common units of Copano Energy, L.L.C. outstanding atNovember 11, 2005. Copano Energy, L.L.C.’s common units trade on TheNASDAQ National Market under the symbol “CPNO.”

 

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**TABLE OF CONTENTS**
|          | ** ** | ** **                                                                                                        | ** ** | **Page** |
|----------|------------|-------------------------------------------------------------------------------------------------------------------|------------|----------|
|     |       | **PART I—FINANCIAL INFORMATION**                                                                             |       |     |   |
| Item 1.  |       | Financial Statements                                                                                              |       | 3        |   |
|     |       | Unaudited Consolidated Balance  Sheets as of September 30, 2005 and December 31, 2004                   |       | 3        |   |
|     |       | Unaudited Consolidated  Statements of Operations for the Three and Nine Months Ended September 30,  2005 and 2004 |       | 4        |   |
|     |       | Unaudited Consolidated  Statements of Cash Flows for the Nine Months Ended September 30, 2005 and  2004           |       | 5        |   |
|     |       | Unaudited Consolidated  Statement of Members’ Capital for the Nine Months Ended September 30, 2005           |       | 6        |   |
|     |       | Notes  to Unaudited Consolidated Financial Statements                                                             |       | 7        |   |
| Item  2. |       | Management’s Discussion and  Analysis of Financial Condition and Results of  Operations                      |       | 30       |   |
| Item  3. |       | Quantitative and Qualitative  Disclosures About Market Risk                                                       |       | 50       |   |
| Item  4. |       | Controls and Procedures                                                                                           |       | 51       |   |
|     |       | **PART II—OTHER  INFORMATION**                                                                               |       |     |   |
| Item 1.  |       | Legal Proceedings                                                                                                 |       | 53       |   |
| Item  4. |       | Submission of Matters to a  Vote of Security Holders                                                              |       | 53       |   |
| Item 6.  |       | Exhibits                                                                                                          |       | 53       |   |

 

2

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**Item 1.**                        FinancialStatements.

**COPANO ENERGY, L.L.C. ANDSUBSIDIARIESCONSOLIDATED BALANCE SHEETS(Unaudited)**

| ** **                                                                                                                                                      | ** ** | **September 30,  2005**                                | ** ** | **December 31,  2004** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                      | ** ** | **(in thousands, except  unit information)** | ** ** |
| **ASSETS**                                                                                                                                                      |       |                                                        |       |                        |       |   |   |   |   |
| Current assets:                                                                                                                                                 |       |                                                        |       |                        |       |   |   |   |   |
| Cash and  cash equivalents                                                                                                                                      |       |                                                        | $          | 29,813                      |       |   |   | $ | 7,015 |   |   |
| Escrow  cash                                                                                                                                                    |       |                                                        | —     |                        |       |   | 1,000 |   |   |
| Accounts  receivable, net                                                                                                                                       |       |                                                        | 92,881     |                        |       |   | 37,045 |   |   |
| Accounts  receivable from affiliates                                                                                                                            |       |                                                        | —     |                        |       |   | 1,141 |   |   |
| Prepayments  and other current assets                                                                                                                           |       |                                                        | 4,802      |                        |       |   | 1,300 |   |   |
| Total  current assets                                                                                                                                           |       |                                                        | 127,496    |                        |       |   | 47,501 |   |   |
| Property, plant and equipment, net                                                                                                                              |       |                                                        | 532,135    |                        |       |   | 119,683 |   |   |
| Intangible assets, net                                                                                                                                          |       |                                                        | 98,411     |                        |       |   | 4,469 |   |   |
| Investment in unconsolidated affiliates                                                                                                                         |       |                                                        | 5,204      |                        |       |   | 4,371 |   |   |
| Other assets, net                                                                                                                                               |       |                                                        | 12,307     |                        |       |   | 2,375 |   |   |
| Total  assets                                                                                                                                                   |       |                                                        | $          | 775,553                     |       |   |   | $ | 178,399 |   |   |
| **LIABILITIES AND MEMBERS’  CAPITAL**                                                                                                                      |       |                                                        |       |                        |       |   |   |   |   |
| Current liabilities:                                                                                                                                            |       |                                                        |       |                        |       |   |   |   |   |
| Accounts  payable                                                                                                                                               |       |                                                        | $          | 99,751                      |       |   |   | $ | 36,960 |   |   |
| Accounts  payable to affiliates                                                                                                                                 |       |                                                        | 570        |                        |       |   | 127 |   |   |
| Note  payable                                                                                                                                                   |       |                                                        | 1,410      |                        |       |   | 350 |   |   |
| Other  current liabilities                                                                                                                                      |       |                                                        | 10,367     |                        |       |   | 777 |   |   |
| Total current  liabilities                                                                                                                                      |       |                                                        | 112,098    |                        |       |   | 38,214 |   |   |
| Long-term debt                                                                                                                                                  |       |                                                        | 402,000    |                        |       |   | 57,000 |   |   |
| Other noncurrent liabilities                                                                                                                                    |       |                                                        | 765        |                        |       |   | 829 |   |   |
| Commitments and contingencies (Note 9)                                                                                                                          |       |                                                        |       |                        |       |   |   |   |   |
| Members’ capital:                                                                                                                                          |       |                                                        |       |                        |       |   |   |   |   |
| Common  units, no par value, 8,545,780 and 7,056,252 units issued and outstanding as  of September 30, 2005 and December 31, 2004, respectively  |       |                                                        | 137,987    |                        |       |   | 94,325 |   |   |
| Class B  units, no par value, 4,830,758 units and 0 units issued and outstanding as of  September 30, 2005 and December 31, 2004, respectively   |       |                                                        | 134,645    |                        |       |   | — |   |   |
| Subordinated  units, no par value, 3,519,126 units outstanding as of  September 30, 2005 and December 31, 2004, respectively                     |       |                                                        | 10,379     |                        |       |   | 10,379 |   |   |
| Paid-in  capital                                                                                                                                                |       |                                                        | 2,574      |                        |       |   | — |   |   |
| Accumulated  deficit                                                                                                                                            |       |                                                        | (20,744    | )                           |       |   | (21,927 | ) |   |
| Deferred  compensation                                                                                                                                          |       |                                                        | (4,151     | )                           |       |   | (421 | ) |   |
|                                                                                                                                                            |       |                                                        | 260,690    |                        |       |   | 82,356 |   |   |
| Total liabilities and members’ capital                                                                                                                     |       |                                                        | $          | 775,553                     |       |   |   | $ | 178,399 |   |   |

 

The accompanying notes are an integral part of these unaudited consolidated financial statements.

3

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**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(Unaudited)**

| ** **                                                             | ** ** | **Three Months  Ended September 30,**            | ** ** | **Nine Months  Ended September 30,** | ** **               |
|------------------------------------------------------------------------|------------|-----------------------------------------------------------------|------------|-----------------------------------------------------|--------------------------|
| ** **                                                             | ** ** | **2005**                                                        | ** ** | **2004**                                            | ** **               | **2005** | ** ** | **2004** | ** ** |
| ** **                                                             | ** ** | **(in thousands, except unit information)** | ** ** |
| Revenue:                                                               |       |                                                            |       |                                                |                     |   |   |   |   |
| Natural gas sales(1)                                                   |       | $                                                               | 155,023    |                                                | $                        | 72,524 |   | $ | 292,036 |   | $ | 195,788 |   |
| Natural gas sales—affiliates                                      |       | —                                                          |       | 73                                                  |                     | 38 |   | 503 |   |
| Natural gas liquids sales                                              |       | 54,327                                                          |       | 44,927                                              |                     | 146,177 |   | 111,241 |   |
| Transportation, compression and processing fees                        |       | 4,383                                                           |       | 2,794                                               |                     | 9,892 |   | 8,498 |   |
| Transportation, compression and processing  fees—affiliates  |       | 7                                                               |       | 18                                                  |                     | 23 |   | 59 |   |
| Other                                                                  |       | 2,927                                                           |       | 459                                                 |                     | 4,473 |   | 1,226 |   |
| Total revenue                                                          |       | 216,667                                                         |       | 120,795                                             |                     | 452,639 |   | 317,315 |   |
| Costs and  expenses:                                                   |       |                                                            |       |                                                |                     |   |   |   |   |
| Cost of natural gas and natural gas liquids(2)                         |       | 184,365                                                         |       | 104,905                                             |                     | 389,489 |   | 279,707 |   |
| Cost of natural gas and natural gas  liquids—affiliates           |       | 2,330                                                           |       | 790                                                 |                     | 3,097 |   | 2,078 |   |
| Transportation                                                         |       | 336                                                             |       | 516                                                 |                     | 1,297 |   | 1,199 |   |
| Transportation—affiliates                                         |       | 113                                                             |       | 125                                                 |                     | 375 |   | 326 |   |
| Operations and maintenance                                             |       | 5,325                                                           |       | 3,186                                               |                     | 11,302 |   | 9,155 |   |
| Depreciation and amortization                                          |       | 5,706                                                           |       | 2,252                                               |                     | 9,371 |   | 5,498 |   |
| General and administrative                                             |       | 4,878                                                           |       | 2,387                                               |                     | 11,408 |   | 5,884 |   |
| Taxes other than income                                                |       | 321                                                             |       | 247                                                 |                     | 713 |   | 748 |   |
| Equity in earnings from unconsolidated affiliates                      |       | (240                                                            | )          | (96                                                 | )                        | (726 | ) | (263 | ) |
| Total costs and expenses                                               |       | 203,134                                                         |       | 114,312                                             |                     | 426,326 |   | 304,332 |   |
| Operating income                                                       |       | 13,533                                                          |       | 6,483                                               |                     | 26,313 |   | 12,983 |   |
| Other income (expense):                                                |       |                                                            |       |                                                |                     |   |   |   |   |
| Interest and other income                                              |       | 168                                                             |       | 25                                                  |                     | 319 |   | 47 |   |
| Interest and other financing costs                                     |       | (8,542                                                          | )          | (3,805                                              | )                        | (10,532 | ) | (11,539 | ) |
| Net income                                                             |       | $                                                               | 5,159      |                                                | $   2,703 |   | $ | 16,100 |   | $ | 1,491 |   |
| Basic net income per equivalent unit                                   |       | $                                                               | 0.35       |                                                | $                        | 1.90 |   | $ | 1.35 |   | $ | 1.05 |   |
| Basic weighted average number of equivalent units                      |       | 14,556                                                          |       | 1,426                                               |                     | 11,943 |   | 1,426 |   |
| Diluted net income per equivalent unit                                 |       | $                                                               | 0.35       |                                                | $                        | 0.98 |   | $ | 1.34 |   | $ | 1.05 |   |
| Diluted weighted average number of equivalent units                    |       | 14,676                                                          |       | 4,728                                               |                     | 12,026 |   | 1,426 |   |

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| (1)   Includes  sales related to purchases/sales with the same counterparty:     |   | $ | 1,949 |   | $ | — |   | $ | 28,970 |   | $ | — |   |
|--------------------------------------------------------------------------------------------|--------|---|-------|--------|---|--------|--------|---|--------|--------|---|--------|--------|
| (2)   Includes  purchases related to purchases/sales with the same counterparty: |   | $ | 2,064 |   | $ | — |   | $ | 29,428 |   | $ | — |   |

 

The accompanying notes are an integral part of these unaudited consolidated financial statements.

4

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**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(Unaudited)**

| ** **                                                                         | ** ** | **Nine Months Ended  September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                                            | ** ** | **2004** | ** ** |
| ** **                                                                         | ** ** | **(in thousands)**                             | ** ** |
| Cash Flows From Operating  Activities:                                             |       |                                                |       |   |   |
| Net income                                                                         |       | $                                                   | 16,100     |   | $ | 1,491 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities: |       |                                                |       |   |   |
| Depreciation and amortization                                                      |       | 9,371                                               |       | 5,498 |   |
| Amortization of debt issue costs                                                   |       | 3,715                                               |       | 912 |   |
| Equity in earnings from unconsolidated affiliates                                  |       | (726                                                | )          | (263 | ) |
| Payment-in-kind interest on subordinated  debt                                     |       | —                                              |       | 814 |   |
| Payment-in-kind interest to preferred  unitholders                                 |       | —                                              |       | 5,464 |   |
| Accretion of preferred unitholders warrant value                                   |       | —                                              |       | 1,247 |   |
| Accretion of subsidiary warrant value                                              |       | —                                              |       | 54 |   |
| Deferred compensation                                                              |       | 684                                                 |       | 40 |   |
| Deferred rent and other                                                            |       | (29                                                 | )          | (45 | ) |
| Deferred revenue                                                                   |       | (19                                                 | )          | — |   |
| Changes  in assets and liabilities, net of acquisitions:                           |       |                                                |       |   |   |
| Accounts receivable                                                                |       | (26,100                                             | )          | (6,579 | ) |
| Accounts receivable from affiliates                                                |       | 1,231                                               |       | (204 | ) |
| Prepayments and other current assets                                               |       | 848                                                 |       | (144 | ) |
| Risk management assets                                                             |       | (3,452                                              | )          | — |   |
| Accounts payable                                                                   |       | 26,139                                              |       | (1,738 | ) |
| Accounts payable to affiliates                                                     |       | 442                                                 |       | (268 | ) |
| Other current liabilities                                                          |       | (16,133                                             | )          | 1,427 |   |
| Net cash provided by operating activities                                          |       | 12,071                                              |       | 7,706 |   |
| Cash Flows From  Investing Activities:                                             |       |                                                |       |   |   |
| Additions to property, plant and equipment and  intangible assets                  |       | (6,377                                              | )          | (6,248 | ) |
| Acquisitions, net of cash acquired                                                 |       | (480,725                                            | )          | (276 | ) |
| Investment in unconsolidated affiliate                                             |       | (197                                                | )          | — |   |
| Escrow cash                                                                        |       | 1,001                                               |       | 1,001 |   |
| Other                                                                              |       | (160                                                | )          | — |   |
| Net cash used in investing activities                                              |       | (486,458                                            | )          | (5,523 | ) |
| Cash Flows From  Financing Activities:                                             |       |                                                |       |   |   |
| Repayments of long-term debt                                                       |       | (57,000                                             | )          | (12,300 | ) |
| Proceeds from long-term debt                                                       |       | 402,000                                             |       | 31,000 |   |
| Repayment of subordinated debt                                                     |       | —                                              |       | (15,199 | ) |
| Repayments of other long-term obligations                                          |       | —                                              |       | (34 | ) |
| Deferred financing costs                                                           |       | (9,465                                              | )          | (1,541 | ) |
| Distributions to unitholders                                                       |       | (14,917                                             | )          | — |   |
| Proceeds from private placement of common units                                    |       | 39,499                                              |       | — |   |
| Proceeds from private placement of Class B units                              |       | 135,503                                             |       | — |   |
| Capital contributions from Pre-Offering Investors                                  |       | 2,574                                               |       | — |   |
| Payment of subscription receivable                                                 |       | —                                              |       | 143 |   |
| Distribution to certain Pre-Offering Investors                                     |       | —                                              |       | (143 | ) |
| Deferred offering costs                                                            |       | (1,009                                              | )          | (2,635 | ) |
| Net cash provided by (used in) financing activities                                |       | 497,185                                             |       | (709 | ) |
| Net increase in cash and cash equivalents                                          |       | 22,798                                              |       | 1,474 |   |
| Cash and cash equivalents, beginning of year                                       |       | 7,015                                               |       | 4,607 |   |
| Cash and cash  equivalents, end of period                                          |       | $                                                   | 29,813     |   | $ | 6,081 |   |

 

The accompanying notes are an integral part of these unaudited consolidated financial statements.

5

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**COPANOENERGY, L.L.C. AND SUBSIDIARIESCONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL(Unaudited)**

| ** ** | ** ** | **Common**              | ** ** | **Class B** | ** ** | **Subordinated**   | ** ** | ** **       | ** ** | **Accumulated**   | ** ** | ** **       | ** ** | ** **  | ** ** |
|------------|------------|-------------------------|------------|------------------|------------|--------------------|------------|------------------|------------|-------------------|------------|------------------|------------|-------------|------------|
| ** ** | ** ** | **Number of**      | ** ** | **Common**       | ** ** | **Number of** | ** ** | **Class B** | ** ** | **Number**        | ** ** | **Subordinated** | ** ** | **Paid-in** | ** ** | **Earnings** | ** ** | **Deferred** | ** ** | ** ** | ** ** |
| ** ** | ** ** | **Units**               | ** ** | **Units**        | ** ** | **Units**          | ** ** | **Units**        | ** ** | **of Units** | ** ** | **Units**        | ** ** | **Capital** | ** ** | **(Deficit)** | ** ** | **Compensation** | ** ** | **Total** | ** ** |
| ** ** | ** ** | **(in thousands)** | ** ** |

| **Balance, December 31, 2004**                          |   |   | 7,056  |   |   |   | $      | 94,325  |   |   |   | — |   |    | $      | —  |   |   | 3,519  |   |   |   | $      | 10,379 |   |   |   | $      | —  |   |   |   | $      | (21,927 | )      |    |   | $ | (421   | ) |   | $ | 82,356  |   |
|---------------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|---------|--------|--------|--------|--------|--------|---------|--------|---------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|---------|--------|--------|--------|--------|---------|--------|---------|--------|---|--------|---|--------|---|---------|--------|
| Capital contributions from Pre-Offering  Investors |   |   | — |   |   |   | — |    |   |   | — |   |   | —  |   |    | — |   |   |   | — |   |   |   | 2,574  |   |   |   | —  |   |   |   | — |    |   | 2,574   |   |
| Private placement of  units                             |   |   | 1,372  |   |   |   | 39,499 |    |   |   | 4,831  |   |   | 135,503 |   |    | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |   | — |    |   | 175,002 |   |
| Offering costs                                          |   |   | — |   |   |   | (251   | )       |   |   | — |   |   | (858    | )      |    | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |   | — |    |   | (1,109  | )      |
| Distributions to unitholders                       |   |   | — |   |   |   | — |    |   |   | — |   |   | —  |   |    | — |   |   |   | — |   |   |   | — |   |   |   | (14,917 | )      |   |   | — |    |   | (14,917 | )      |
| Issuance of restricted  units                           |   |   | 117    |   |   |   | 4,414  |    |   |   | — |   |   | —  |   |    | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |   | (4,414 | )       |   | —  |   |
| Stock-based  compensation                               |   |   | — |   |   |   | — |    |   |   | — |   |   | —  |   |    | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |   | 684    |    |   | 684     |   |
| Net income                                              |   |   | — |   |   |   | — |    |   |   | — |   |   | —  |   |    | — |   |   |   | — |   |   |   | — |   |   |   | 16,100  |   |   |   | — |    |   | 16,100  |   |
| **Balance,  September 30, 2005**                   |   |   | 8,545  |   |   |   | $      | 137,987 |   |   |   | 4,831  |   |    | $      | 134,645 |   |   | 3,519  |   |   |   | $      | 10,379 |   |   |   | $      | 2,574   |   |   |   | $      | (20,744 | )      |    |   | $ | (4,151 | ) |   | $ | 260,690 |   |

 

The accompanying notes are an integral part of these unaudited consolidated financial statements.

6

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS**

**Note 1—Organizationand Basis of Presentation**

*Organization*

Copano Energy, L.L.C. (“CE”), a Delaware limitedliability company, was formed in August 2001 to acquire entities owningbusinesses operating under the Copano name since 1992. CE, through its whollyowned subsidiaries, provides midstream energy services, including gathering,transportation, treating, processing and conditioning services in the TexasGulf Coast region and, as a result of the acquisition of ScissorTail Energy,LLC (“ScissorTail”) on August 1, 2005, in Central and Eastern Oklahoma****(see Note 4). CE and its subsidiaries collectively arereferred to as the “Company”.

The Company’s natural gas pipelines collect naturalgas from designated points near producing wells and transport these volumes tothird-party pipelines, the Company’s gas processing plants, third partyprocessing plants, local distribution companies, power generation facilitiesand industrial consumers. Natural gas delivered to the Company’s gas processingplants, either on the Company’s pipelines or a third-party pipeline, istreated to remove contaminants, conditioned or processed to extract mixednatural gas liquids, or NGLs, and then fractionated or separated into selectcomponent NGL products, including ethane, propane, isobutene, normal butane,natural gasoline and stabilized condensate. The Company also owns and operatesan NGL products pipeline extending from the Company’s gas processing plant tothe Houston area. The Company refers to its natural gas pipeline Texas operatingsubsidiaries collectively as “Texas Gulf Coast Pipelines,” to its Texasprocessing and related activities collectively as “Texas Gulf Coast Processing”and to its operations in Central and Eastern Oklahoma as “Mid-ContinentOperations.”

On November 15, 2004,CE completed its initial public offering (the “Offering”) of 5,750,000 commonunits, inclusive of 750,000 common units that were issued as a result of theunderwriters’ exercise of their over-allotment option. The common units issuedin the Offering were sold at $20.00 per common unit and the net proceeds fromthe Offering were used (i) to redeem CE’s redeemable preferred units fromcertain of CE’s investors existing prior to the Offering (the “Pre-OfferingInvestors”), (ii) to reduce existing indebtedness under the CPG CreditAgreement (as defined herein), (iii) to reduce existing indebtedness undera term loan entered into in 2001, (iv) to pay other obligations, (v) topay expenses of the Offering and (vi) to redeem common units, on a prorata basis, from certain Pre-Offering Investors.

*Basis ofPresentation and Principles of Consolidation*

The accompanying unaudited consolidated financialstatements and related notes include the assets, liabilities and results ofoperations of the Company for each of the periods presented. Although CE,through certain subsidiaries, owns a 62.5% equity investment in Webb/DuvalGatherers (“WDG”), a Texas general partnership, and a majority interest inSouthern Dome, LLC (“Southern Dome”), a Delaware limited liability company, theCompany accounts for both of these investments using the equity method ofaccounting because the minority general partners or members have substantiveparticipating rights with respect to the management of WDG and Southern Dome. Allsignificant intercompany accounts and transactions are eliminated in theconsolidated financial statements.

The accompanying consolidated financial statementshave been prepared without audit pursuant to the rules and regulations ofthe Securities and Exchange Commission. Accordingly, the statements reflect allnormal and recurring adjustments that are, in the opinion of management,necessary for a fair presentation of the results of operations for the interimperiods. Certain information and notes normally included in financialstatements prepared in accordance with generally accepted accounting principleshave been condensed or omitted pursuant to such rules and regulations. However,management believes that 

7

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 1—Organizationand Basis of Presentation (Continued)**

the disclosures areadequate to make the information presented not misleading. These interimfinancial statements should be read in conjunction with the auditedconsolidated financial statements and notes thereto contained in the Company’sAnnual Report on Form 10-K for the year ended December 31, 2004.

Copano General Partners, Inc. (“CGP”) and CopanoEnergy Finance Corporation (“CEFC”), Delaware corporations and wholly ownedsubsidiaries of CE, are the only entities within the consolidated group subjectto federal income taxes. CGP’s operations primarily include its indirectownership of the managing general partner interest in certain of the Texas GulfCoast Pipelines entities and CEFC was recently formed in July 2005. As of December 31,2004, CGP had estimated a net operating loss (“NOL”) carryforward ofapproximately $265,000, for which a valuation allowance had been recorded. Duringthe nine months ended September 30, 2005, the Company determined that CGP hasutilized this NOL carryforward. No income tax expense was recognized for theinterim period presented and except for income allocated to CGP, income istaxable directly to the members holding the membership interests in CE.

The number of CE’s equityunits outstanding and per unit amounts have been restated for the three andnine months ended September 30, 2004 to reflect the conversion or exchangeof pre-Offering units into post-Offering common and subordinated unitsimmediately prior to the completion of the Offering.

**Note 2—New Accounting Pronouncements**

*Share-Based Payment*

In December 2004, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”)No. 123 (revised 2004), or SFAS No. 123(R), *“Share-BasedPayment,”* which establishes accounting standards for all transactions in which anentity exchanges its equity instruments for goods or services. SFAS No. 123(R) focusesprimarily on accounting for transactions with employees and carries forward withoutchange to prior guidance for share-based payments for transactions withnon-employees. SFAS No. 123(R) eliminates the intrinsic valuemeasurement objective in Accounting Principles Board Opinion (“APB”) No. 25and generally requires the Company to measure the cost of employee servicesreceived in exchange for an award of equity instruments based on the fair value of the award on the date of the grant.

The standard requires grant date fair value to beestimated using either an option-pricing model that is consistent with theterms of the award or a market observed price, if such a price exists. Suchcost must be recognized over the period during which an employee is required toprovide services in exchange for the award (which is usually the vesting period).The standard also requires the Company to estimate the number of instrumentsthat will ultimately be issued, rather than accounting for forfeitures as theyoccur. The Company is required to apply SFAS No. 123(R) to all equityawards granted, modified or settled by January 1, 2006. The Company isalso required to use either the “modified prospective method” or the “modifiedretrospective method.” Under the modified prospective method, the Company mustrecognize compensation cost for all awards granted after the Company adopts thestandard and for the unvested portion of previously granted awards that areoutstanding on that date. Under the modified retrospective method, the Companymust restate previously issued financial statements to recognize the amountsthe Company previously calculated and reported on a pro forma basis, as if theprior standard had been adopted. Under both methods, the Company is permittedto use either a straight line or an accelerated 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 2—NewAccounting Pronouncements (Continued)**

method to amortize thecost as an expense for awards with graded vesting. The standard permits andencourages early adoption.

The Company has commencedthe analysis of the impact of SFAS No. 123(R), but has not yetdecided: (1) whether the Company will elect early adoption, (2) ifthe Company elects early adoption, at what date the Company would do so, (3) whetherthe Company will use the modified prospective method or elect to use themodified retrospective method and (4) whether the Company will elect touse straight line amortization or an accelerated method. Additionally, theCompany cannot predict with reasonable certainty the number of options thatwill be unvested and outstanding upon adoption. Accordingly, the Company cannotcurrently quantify with precision the effect that this standard would have onthe financial position or results of operations in the future, except that theCompany probably will recognize a greater expense for any awards that theCompany may grant in the future than the Company would recognize using thecurrent guidance. If the Company were to adopt SFAS No. 123(R) usingthe modified retrospective method, the Company’s net income would have beenapproximately $250,000 less than that reported for the nine months ended September 30,2005 (Note 6)**.**

*Exchanges ofNonmonetary Assets an amendment of APB No. 29*

In December 2004, theFASB issued SFAS No. 153, *“Exchanges of NonmonetaryAssets an amendment of APB Opinion No. 29.”* This statementamends APB No. 29 to eliminate the exception for nonmonetaryexchanges of similar productive assets and replaces it with a general exceptionfor exchanges of nonmonetary assets that do not have commercial substance. Thestatement specifies that a nonmonetary exchange has commercial substance if thefuture cash flows of the entity are expected to change significantly as aresult of the exchange. This statement was adopted by the Company beginningJuly 1, 2005. The adoption of this statement had no impact on theCompany’s previously issued financial statements and is not expected to have amaterial impact on future financial statements.

*Accounting forConditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143*

In March 2005, the FASB issued FASBInterpretation No. (“FIN”) 47, *“Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143.”*FIN 47 clarifies that the term, conditional asset retirement obligation asused in SFAS No. 143, “Accountingfor Asset Retirement Obligations,” refers to a legal obligation toperform an asset retirement activity in which the timing and/or method ofsettlement are conditional upon a future event that may or may not be withinthe control of the entity. Even though uncertainty about the timing and/ormethod of settlement exists and may be conditional upon a future event, theobligation to perform the asset retirement activity is unconditional. Accordingly,an entity is required to recognize a liability for the fair value of aconditional asset retirement obligation if the fair value of the liability canbe reasonably estimated. Uncertainty about the timing and/or method ofsettlement of a conditional asset retirement obligation should be factored intothe measurement of the liability when sufficient information exists. The fairvalue of a liability for the conditional asset retirement obligation should berecognized when incurred generally upon acquisition, construction ordevelopment or through the normal operation of the asset. SFAS No. 143acknowledges that in some cases, sufficient information may not be available toreasonably estimate the fair value of an asset retirement obligation. FIN 47also clarifies when an entity would have sufficient information to reasonably 

9

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 2—NewAccounting Pronouncements (Continued)**

estimatethe fair value of an asset retirement obligation. FIN 47 is effective nolater than the end of periods ending after December 15, 2005. Retrospectiveapplication for interim financial information is permitted but is not required.Early adoption of FIN 47 is encouraged. Management of the Company iscurrently evaluating what impact FIN 47 will have on the Company’sconsolidated financial statements but, at this time, does not believe that theadoption of FIN 47 will have a significant impact on the Company’sfinancial position, results of operations or cash flows.

*Accounting Changesand Error Corrections*

In May 2005, the FASBissued SFAS No. 154, *“Accounting Changes andError Corrections.”* SFAS No. 154 requires companies torecognize changes in accounting principle, including changes required by a newaccounting pronouncement when the pronouncement does not include specifictransition provisions, retrospectively to prior periods’ financial statements.SFAS No. 154 is effective for accounting changes and corrections oferrors made in fiscal years beginning after December 15, 2005. The Companydoes not believe that the adoption of SFAS No. 154 will have amaterial effect on its financial position or results of operations.

*Accounting forPurchases and Sales of Inventory with the Same Counterparty*

In September 2005,the Emerging Issues Task Force (“EITF”) of the FASB reached consensus on theissue of accounting for buy/sell arrangements as part of its EITF Issue No. 04-13,*“Accounting for Purchases and Sales of Inventorywith the Same Counterparty”* (Issue 04-13). As part of Issue 04-13,the EITF is requiring that all buy/sell arrangements be reflected on a netbasis, such that the purchase and sale are netted and shown as either a netpurchase or a net sale in the income statement. This requirement is effectivefor new arrangements entered into after March 31, 2006. If thisrequirement had been effective for the three and nine months ended September 30,2005 and 2004, the reported natural gas sales revenues and the reported cost ofnatural gas and natural gas liquids would be reduced by the amounts shown infootnotes (1) and (2) to the consolidated statements of operations. TheCompany does not expect that the adoption of Issue 04-13 will have a materialeffect on the Company’s financial position, results of operations or cashflows.

**Note 3—Intangible Assets**

Intangible assets consist of rights-of-way, easementsand an acquired customer relationship, which the Company amortizes over theterm of the agreement or estimated useful life. As of September 30, 2005and December 31, 2004, the weighted average amortization period for theCompany’s intangible assets was 9.7 years and 10.1 years,respectively. Amortization expense was $1,061,000 and $108,000 for the three monthsended September 30, 2005 and 2004, respectively. Amortization expense was$1,278,000 and $325,000 for the nine months ended September 30, 2005 and2004, respectively. Estimated aggregate

10

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 3—IntangibleAssets (Continued)**

amortization expense remaining for 2005 and each ofthe five succeeding fiscal years is approximately: *2005—*$1,535,000, *2006—*$6,133,000;*2007—*$5,509,000; *2008—*$5,150,000; *2009—*$5,082,000; and *2010—*$5,060,000. Intangible assetsconsisted of the following (in thousands):

| ** **                            | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2005**               | ** ** | **2004**              | ** ** |
| Rights-of-way  and easements, at cost |       |                   | $          | 59,330                |       |   |   | $ | 6,552 |   |   |
| Contracts                             |       |                   | 42,442     |                  |       |   | — |   |   |
| Customer  relationship                |       |                   | 725        |                  |       |   | 725 |   |   |
| Less accumulated  amortization        |       |                   | (4,086     | )                     |       |   | (2,808 | ) |   |
| Intangible  assets, net               |       |                   | $          | 98,411                |       |   |   | $ | 4,469 |   |   |

 

**Note 4—Acquisitions**

*Acquisition ofScissorTail Energy, LLC*

On August 1, 2005, the Company completed its acquisitionof all of the membership interests in Tulsa-based ScissorTail for $499,102,000(the “ScissorTail Acquisition”). ScissorTail provides natural gas midstreamservices in Central and Eastern Oklahoma and its assets primarily consist ofgathering pipelines and three processing plants. In connection with theScissorTail Acquisition, the Company, through ScissorTail, now operates andholds a majority interest in Southern Dome in partnership with the priorScissorTail ownership group. Southern Dome was formed to engage in themidstream gas gathering and processing business and related operations in OklahomaCounty, Oklahoma. In connection with the ScissorTail Acquisition, CE issued85,998 restricted common units and 169,002 options to acquire common units toemployees of ScissorTail subject, in each case, to a five-year vestingschedule.

The Companyfinanced the ScissorTail Acquisition and related transactions and costs withproceeds from the following:

·       Borrowingsof approximately $179.0 million of the $232.0 million initiallyborrowed under the new Credit Facility discussed in Note 5;

·       Borrowingsof $170.0 million under the new Term Loan Facility discussed in Note 5;and

·       Netproceeds from a $174.0 million private placement of equity to certaininstitutional investors discussed in Note 6.

Thefollowing is an estimate of the purchase price for the ScissorTail Acquisition(in thousands):

| Purchase price  for ScissorTail membership interests  |   | $      | 500,000 |   |
|-------------------------------------------------------|--------|--------|---------|--------|
| Estimated net  working capital adjustments            |   | (4,740 | )       |
| Estimated  acquisition costs                          |   | 3,842  |    |
| Total purchase  price for the ScissorTail Acquisition |   | $      | 499,102 |   |

 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 4—Acquisitions(Continued)**

With the assistance of athird party valuation firm, management has prepared a preliminary assessment ofthe fair value of the property, plant and equipment and intangible assets ofScissorTail as of August 1, 2005. Using the preliminary assessment, thepurchase price has been allocated as of August 1, 2005 as presented below(in thousands).

| Cash and cash  equivalents            |   | $       | 18,377  |   |
|---------------------------------------|--------|---------|---------|--------|
| Accounts  receivable                  |   | 29,735  |    |
| Prepayments and  other current assets |   | 1,817   |    |
| Property, plant  and equipment        |   | 413,980 |    |
| Intangibles                           |   | 95,128  |    |
| Other assets                          |   | 2,090   |    |
| Accounts payable                      |   | (36,483 | )       |
| Other current  liabilities            |   | (25,542 | )       |
|                                  |   | $       | 499,102 |   |

 

All liabilities assumed were at their fair values. Thefair value of intangibles is estimated to be $95,128,000. There were noidentified intangibles which were determined to have indefinite lives.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 4—Acquisitions(Continued)**

The following tablepresents selected unaudited pro forma financial information incorporating thehistorical (pre-acquisition) results of ScissorTail as if the ScissorTailAcquisition had occurred at the beginning of each of the periods presented asopposed to the actual date that the acquisition occurred. Excluded from the proforma financial information are certain non-recurring charges of$1.6 million related to the write-off of the remaining debt issuance costsrelated to senior indebtedness existing prior to the ScissorTail Acquisition. Thepro forma information is based upon preliminary data currently available andincludes certain estimates and assumptions made by management. As a result,this preliminary information is not necessarily indicative of the Company’sfinancial results had the transactions actually occurred at the beginning ofeach of the periods presents. Likewise, the following unaudited pro formafinancial information is not necessarily indicative of future financial resultsof the Company.

| ** **                                     | ** ** | **Three Months  Ended September 30,**        | ** ** | **Nine Months  Ended September 30,** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                     | ** ** | **2005**                                                    | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                     | ** ** | **(in thousands,  except unit information)** | ** ** |
| Pro Forma  Earnings Data:                      |       |                                                        |       |                                                |       |   |   |   |   |
| Revenue                                        |       | $                                                           | 246,450    |                                                | $          | 186,155 |   | $ | 637,925 |   | $ | 493,500 |   |
| Costs and expenses                             |       | $                                                           | 230,299    |                                                | $          | 185,535 |   | $ | 595,800 |   | $ | 475,860 |   |
| Operating income                               |       | $                                                           | 16,151     |                                                | $          | 620 |   | $ | 42,125 |   | $ | 17,640 |   |
| Income (loss) before extraordinary items       |       | $                                                           | 5,638      |                                                | $          | (10,068 | ) | $ | 15,083 |   | $ | (9,861 | ) |
| Net income (loss)                              |       | $                                                           | 5,638      |                                                | $          | (10,068 | ) | $ | 15,083 |   | $ | (9,861 | ) |
| Basic net income (loss) per equivalent unit:   |       |                                                        |       |                                                |       |   |   |   |   |
| As reported equivalent units outstanding       |       | 14,556                                                      |       | 1,426                                               |       | 11,943 |   | 1,426 |   |
| Pro forma units outstanding                    |       | 16,761                                                      |       | 7,629                                               |       | 16,761 |   | 7,629 |   |
| As reported net income per unit                |       | $                                                           | 0.35       |                                                | $          | 1.90 |   | $ | 1.35 |   | $ | 1.05 |   |
| Pro forma net income (loss) per unit           |       | $                                                           | 0.34       |                                                | $          | (1.32 | ) | $ | 0.90 |   | $ | (1.29 | ) |
| Diluted net income (loss) per equivalent unit: |       |                                                        |       |                                                |       |   |   |   |   |
| As reported equivalent units outstanding       |       | 14,676                                                      |       | 4,728                                               |       | 12,026 |   | 1,426 |   |
| Pro forma units outstanding                    |       | 16,881                                                      |       | 7,629                                               |       | 16,843 |   | 7,629 |   |
| As reported net income per unit                |       | $                                                           | 0.35       |                                                | $          | 0.98 |   | $ | 1.34 |   | $ | 1.05 |   |
| Pro forma net  income (loss) per unit          |       | $                                                           | 0.33       |                                                | $          | (1.32 | ) | $ | 0.90 |   | $ | (1.29 | ) |

 

**Note 5—Long-Term Debt**

Asummary of the Company’s debt follows (in thousands):

| ** **           | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|----------------------|------------|------------------------|------------|-----------------------|------------|
| ** **           | ** ** | **2005**               | ** ** | **2004**              | ** ** |
| Long-term debt:      |       |                   |       |                  |       |   |   |   |   |
| Credit Facility      |       |                   | $          | 232,000               |       |   |   | $ | — |   |   |
| Term Loan Facility   |       |                   | 170,000    |                  |       |   | — |   |   |
| CPG Credit Agreement |       |                   | —     |                  |       |   | 48,000 |   |   |
| CHC Facility         |       |                   | —     |                  |       |   | 9,000 |   |   |
| Total                |       |                   | $          | 402,000               |       |   |   | $ | 57,000 |   |   |

 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 5—Long-Term Debt (Continued)**

*Credit Facility*

On August 1, 2005, CE entered into a new $350million senior secured revolving credit facility (the “Credit Facility”) withBank of America, N.A., as Administrative Agent, Banc of America Securities LLC,as Sole Lead Arranger and Sole Book Manager and a group of financialinstitutions, as lenders. The Credit Facility includes a $25 millionsublimit for the issuance of standby letters of credit and matures on July 31,2010.

On August 1, 2005, CE borrowed $232,000,000 underthe Credit Facility to: (i) partially finance the ScissorTail Acquisition discussedin Note 4 and (ii) to repay in full indebtedness outstanding under the CPGCredit Agreement and the CHC Facility discussed below. Additionally, inconnection with the ScissorTail Acquisition, a $900,000 standby letter ofcredit was assumed by CE, which remains outstanding at September 30, 2005.Future borrowings under the Credit Facility are available for acquisitions,capital expenditures, working capital and general corporate purposes. TheCredit Facility does not provide for the type of working capital borrowingsthat would be eligible, pursuant to CE’s limited liability company agreement,to be considered available cash distributable to unitholders. The CreditFacility is available to be drawn on and repaid without restriction so long asthe Company is in compliance with the terms of the Credit Facility, includingcertain financial covenants.

The Credit Facility contains various covenants thatlimit CE and certain of its operating subsidiaries’ ability to grant certainliens; make certain loans and investments; make certain capital expendituresoutside the Company’s current lines of business or certain related lines ofbusiness; make distributions other than from available cash (as defined in CE’slimit liability company agreement); merge or consolidate with or into a thirdparty; or engage in certain asset dispositions, including a sale of all orsubstantially all of the Company’s assets. Additionally, the Credit Facilitylimits CE and certain of its operating subsidiaries’ ability to incuradditional indebtedness with certain exceptions, including under the Term LoanFacility (as discussed below), purchase money indebtedness and indebtednessrelated to capital or synthetic leases not to exceed $5.0 million, unsecuredindebtedness not to exceed $5.0 million and unsecured indebtedness qualifyingas subordinated debt.

The Credit Facilityalso contains covenants, which, among other things, requires CE and certain ofits subsidiaries, on a consolidated basis, to maintain specified ratios orconditions as follows:

·       EBITDA(as defined) to interest expense of not less than 2.5 to 1.0 through September 30,2005, 2.75 to 1.0 from December 31, 2005 through June 30, 2006 and3.0 to 1.0 thereafter;

·       EBITDAminus maintenance capital expenditures to consolidated fixed charges of notless than 1.5 to 1.0 through September 30, 2005 and 1.75 to 1.0thereafter;

·       totaldebt to EBITDA of not more than 5.5 to 1.0 through September 30, 2005, 5.0to 1.0 from December 31, 2005 through June 30, 2006 and 4.75 to 1.0thereafter; and

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0 through September 30,2005 and 3.5 to 1.0 thereafter.

Based upon the senior debt to EBITDA ratio calculatedas of September 30, 2005 (utilizing trailing four quarters’ EBITDA asdefined under the Credit Facility), CE has approximately $118.0 million ofunused capacity under the Credit Facility.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 5—Long-TermDebt (Continued)**

The obligations under the Credit Facility are securedby first priority liens on substantially all of the Company’s assets andsubstantially all of the assets of the Company’s subsidiaries (other than WDG,Southern Dome and certain subsidiaries with insignificant assets). Additionally,the obligations under the Credit Facility are guaranteed by substantially allof CE’s subsidiaries (other than WDG, Southern Dome and certain subsidiarieswith insignificant assets).

At CE’s election, interest under the Credit Facilityis determined by reference to (i) the British Bankers Association LIBORrate, or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum or (ii) thehigher of the federal funds rate plus 0.5% or the prime rate plus, in eithercase, an applicable margin between 0.25% and 1.25% per annum. Interest ispayable quarterly for prime rate loans and at the applicable maturity date forLIBOR loans, except that if the interest period for a LIBOR loan is six months,interest will be paid at the end of each three-month period.

If an event ofdefault occurs under the Credit Facility, the lenders would be able toaccelerate the maturity of the obligations outstanding under the CreditFacility and exercise other rights and remedies. Each of the following would bean event of default:

·       failureto pay any principal when due or any interest, fees or other amount withincertain grace periods;

·       failureto perform or otherwise comply with the covenants in the credit agreement orother loan documents, subject, in certain instances, to certain grace periods;

·       defaultby the Company on the payment of any other indebtedness in excess of $5.0million or any default in the performance of any obligation or condition withrespect to such indebtedness beyond the applicable grace period if the effectof the default is to permit or cause the acceleration of the indebtedness;

·       bankruptcyor insolvency events involving CE or its subsidiaries;

·       theentry of, and failure to pay, one or more adverse judgments in excess of $5.0million against which enforcement proceedings are brought or that are notstayed pending appeal; and

·       achange of control (as defined in the Credit Facility).

The effective average interest rate on borrowingsunder the Credit Facility was 5.95% and the quarterly commitment fee on theunused portion of the Credit Facility was 0.3% as of September 30, 2005. Interestand other financing costs related to the Credit Facility totaled $2,549,000 forthe period from August 1, 2005 through September 30, 2005. Costsincurred in connection with the establishment of this credit facility are beingamortized over the term of the Credit Facility, and as of September 30,2005, the unamortized portion of debt issue costs totaled $4,918,000.

Management believes thatthe Company is in compliance with the covenants under the Credit Facility as ofSeptember 30, 2005. If an event of default exists under the CreditFacility, the lenders will be able to accelerate the maturity of the creditagreement and exercise other rights and remedies.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 5—Long-TermDebt (Continued)**

*Term Loan Facility*

On August 1, 2005, CE entered into a $170,000,000senior unsecured term loan facility (the “Term Loan Facility”) with Banc ofAmerica Bridge LLC, as the Lender and Banc of America Securities LLC, as SoleLead Arranger and Sole Book Manager. The proceeds from the Term Loan Facilitywere used to pay a portion of the purchase price of the ScissorTail Acquisition.

The Term Loan Facility matures on August 1, 2006.Any outstanding term loans on August 1, 2006 (the “Conversion Date”) willbe automatically converted into new term loans with a six year term (the “RolloverLoans”) subject to satisfaction of certain conditions. On and after theConversion Date, the Lenders (as defined in the Term Loan Facility) holding atleast $42.5 million of the Rollover Loans may elect to exchange their RolloverLoans for exchange notes, which will be governed by the Exchange Note Indenture(as defined in the Term Loan Facility). The obligations under the Term LoanFacility are general unsecured obligations of CE and certain of itssubsidiaries and are guaranteed by substantially all of CE’s subsidiaries(other than WDG, Southern Dome and certain subsidiaries with insignificantassets).

The Term Loan Facility contains customary restrictivecovenants pertaining to management and operations of CE and its subsidiaries,which are substantially similar to those contained in the Credit Facility. TheTerm Loan Facility also includes the same financial covenants as thosecontained in the Credit Facility except that the required interest expense andconsolidated fixed charge coverage ratios have been set at 0.5 to 1.0 lower andthe permitted total debt and total senior debt to EBITDA ratios have been set0.5 to 1.0 higher. Generally, amounts outstanding under the Term Loan Facilitywill bear interest at a base rate being the greater of (i) three-monthLIBOR plus an applicable margin initially equal to 5% per annum or (ii) 8.5%per year; provided that the rates and margins increase by 0.5% per quarterwhile the Term Loan Facility remains outstanding subject to a cap of 11% (subjectto certain additional interest rate increases in certain circumstances). Inaddition, the Term Loan Facility contains covenants that obligate CE to usecommercially reasonable efforts to refinance the Term Loan Facility as promptlyas practicable and, within certain time periods, to prepare the Exchange NoteIndenture and to register the related exchange notes with the Securities andExchange Commission.

The Term Loan Facility also includes events of defaultsubstantially similar to those contained in the Credit Facility. If an event ofdefault under the Term Loan Facility shall occur and be continuing, theprincipal amount outstanding thereunder, together with all accrued unpaidinterest and other amounts owed thereunder, may be declared immediately due andpayable.

The effective average interest rate on borrowingsunder the Term Loan Facility was 8.69% as of September 30, 2005. Interestand other financing costs related to the Term Loan Facility totaled $4,058,000for the period from August 1, 2005 through September 30, 2005. Costsincurred in connection with the establishment of this credit facility are beingamortized over the estimated term of the Term Loan Facility, and as of September 30,2005, the unamortized portion of debt issue costs totaled $2,336,000.

Management believes thatthe Company is in compliance with the covenants under the Term Loan Facility asof September 30, 2005. If an event of default exists under the Term LoanFacility, the lenders will be able to accelerate the maturity of the creditagreement and exercise other rights and remedies.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 5—Long-TermDebt (Continued)**

*CPG CreditAgreement*

Prior to the consummation of the Credit Facility,Copano Pipelines Group, L.L.C., a wholly owned subsidiary, and certain of TexasGulf Coast Pipelines’ operating subsidiaries had a $100 million revolvingcredit agreement (the “CPG Credit Agreement”), which was to mature on February 12,2008. On August 1, 2005, this credit facility was paid in full andterminated using the proceeds from the Credit Facility.

Interest and otherfinancing costs related to the CPG Credit Agreement totaled $3,468,000 and$2,115,000 for the nine months ended September 30, 2005 and 2004,respectively. Costs incurred in connection with the establishment of thisfacility and subsequent amendments were being amortized over the remaining termof the CPG Credit Agreement, and effective with the early termination of thisagreement in August 2005, the Company charged $1,472,000 to interestexpense, representing the balance of the unamortized debt issuance costs.

*CHC Facility*

Prior to the consummation of the Credit Facility,Copano Houston Central, L.L.C., a wholly owned subsidiary, and certain of itssubsidiaries entered into a $12 million secured revolving credit facility (the “CHCFacility”) with Comerica Bank due January 31, 2007. On August 1,2005, this credit facility was paid in full and terminated using the proceedsfrom the Credit Facility.

Interest and otherfinancing costs related to the CHC Facility totaled $456,000 for the ninemonths ended September 30, 2005. Costs incurred in connection with theestablishment of this credit facility were being amortized over the term of theCHC Facility, and effective with the early termination of this facility in August 2005,the Company charged $136,000 to interest expense, representing the balance ofthe unamortized debt issuance costs.

**Note 6—Members’ Capital and Distributions**

*Common Units andSubordinated Units*

As of September 30, 2005, 8,545,780 common unitsand 3,519,126 subordinated units were outstanding. Pre-Offering Investors andtheir assignees owned an aggregate of 1,288,252 common units, employees andboard members owned an aggregate 135,070 restricted common units, privateinvestors owned an aggregate of 1,372,458 common units and the public owned anaggregate of 5,750,000 common units. Pre-Offering Investors and their assigneesowned all of the outstanding subordinated units outstanding.

Pursuant to CE’s limited liability company agreement,the Pre-Offering Investors have agreed to reimburse the Company for general andadministrative expenses in excess of stated levels (subject to certainlimitations) for a period of three years beginning on January 1, 2005. Specifically,to the extent general and administrative expenses exceed certain levels, theportion of the general and administrative expenses ultimately funded by theCompany (subject to certain adjustments and exclusions) will be limited, orcapped. For the year ended December 31, 2005, the “cap” limits the Company’sgeneral and administrative expense obligations to $1.5 million per quarter(subject to certain adjustments and 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 6—Members’Capital and Distributions (Continued)**

exclusions). During thisthree-year period, the quarterly limitation on general and administrativeexpenses will be increased by 10% of the amount by which EBITDA (as defined)for any quarter exceeds $5.4 million. On May 12, 2005, Pre-OfferingInvestors made capital contributions to CE in the aggregate amount of$1,424,000 as a reimbursement of excess general and administrative expenses forthe three months ended March 31, 2005. On August 12, 2005,Pre-Offering Investors made capital contributions to CE in the aggregate amountof $1,150,000 as a reimbursement of excess general and administrative expensefor the three months ended June 30, 2005. On November 10, 2005, Pre-OfferingInvestors made capital contributions to CE in the aggregate amount of$1,494,000 as a reimbursement of excess general and administrative expense forthe three months ended September 30, 2005. The Pre-Offering Investorsprimarily used escrowed funds that CE had distributed to them prior to theOffering to make these contributions.

On August 1, 2005,the Company issued 1,372,458 common units in a private equity placement tocertain institutional investors for an aggregate consideration of $39.5 millionto partially fund the ScissorTail acquisition and related costs (Note 4). Holdersof these common units are entitled to piggy back and demand registration rightsas described in the Registration Rights Agreement.

*Class B Units*

On August 1, 2005, CEissued 4,830,758 Class B units in a private equity placement to certaininstitutional investors for an aggregate consideration of $135.5 million topartially fund the ScissorTail Acquisition and related costs (Note 4). Pursuantto the terms of the Class B units, the holders of the Class B units wereentitled to quarterly distributions equal to 110% of the quarterly distributionper unit to be received by the common units, which was applicable unless anduntil the existing unitholders approved the conversion of the Class Bunits into common units, had no voting rights other than required by law and weresubordinated to the common units on dissolution and liquidation. On October 27,2005, CE’s unitholders approved the conversion of each of the Class B unitsinto one common unit and the issuance of 4,830,758 additional common units uponsuch conversion. Former holders of these units are entitled to piggy back anddemand registration rights with respect to the common units received in theconversion as described in the Registration Rights Agreement.

*Restricted CommonUnits*

Restricted units are awarded under CE’s long-termincentive plan and are common units that vest over a period of time and thatduring such time are subject to forfeiture. In addition, restricted units willvest upon a change of control of CE, unless provided otherwise by theCompensation Committee of CE’s Board of Directors. Distributions made onrestricted units may be subjected to the same vesting provisions as therestricted units. The restricted units are intended to serve as a means ofincentive compensation for performance and not primarily as an opportunity toparticipate in the equity appreciation of the common units. Therefore, planparticipants will not pay any consideration for the common units they receiveand CE will receive no remuneration for the units.

During the nine months ended September 30, 2005,CE awarded 117,070 restricted common units to employees, including 85,998restricted units awarded at the time of the ScissorTail Acquisition toScissorTail employees. These restricted common units had an aggregate intrinsicvalue of $4,414,000. Of these restricted unit grants, 15,400 vest in equalone-third annual installments commencing on the first 

18

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 6—Members’Capital and Distributions (Continued)**

anniversaryof the grant date, 11,720 vest in equal one-fourth annual installmentscommencing on the first anniversary of the grant date, 89,950 vest in equalone-fifth annual installments commencing on the first anniversary of the grantdate and all of these restricted units vest upon a change of control, death,disability or, in certain circumstances, retirement. The aggregate intrinsicvalue of the units is amortized into general and administrative expense overthe respective vesting periods. The Company recognized non-cashcompensation expense of $459,000 and $684,000 related to the amortization ofrestricted units outstanding during the three and nine months ended September 30,2005, respectively.

*Distributions*

The holders of the common and subordinated units areentitled to participate in distributions. The common units have the right toreceive a minimum quarterly distribution of $0.40 per unit, plus any arrearageson the common units, before any distribution is made to the holders of thesubordinated units. Subordinated units do not accrue distribution arrearages. Afterthe expiration of the subordination period as defined in CE’s limited liabilitycompany agreement, common units will no longer be entitled to arrearages.

On January 18, 2005, the Board of Directorsdeclared an adjusted cash distribution for the partial quarterly period fromthe closing of the Offering on November 15, 2004 through December 31,2004 of $0.20 per unit for all outstanding common and subordinated units. Thedistribution totaling $2,115,000 was paid on February 14, 2005 to holdersof record at the close of business on February 1, 2005.

On April 15, 2005 and pursuant to the provisionsof the Company’s limited liability company agreement, the Board of Directorsdeclared and the Company paid a cash distribution of $533,000 to certainPre-Offering Investors for reimbursement of their respective tax obligationsattributable to their ownership interest in the Company for the period from January 1,2004 through November 14, 2004, the day prior to the closing of theOffering.

On April 18, 2005, the Board of Directorsdeclared a cash distribution for the three months ended March 31, 2005 of$0.42 per unit for all outstanding common and subordinated units. Thedistribution totaling $4,450,000 was paid on May 13, 2005 to holders ofrecord at the close of business on May 2, 2005.

On July 15, 2005, the Board of Directors declareda cash distribution for the three months ended June 30, 2005 of $0.45 perunit for all outstanding common and subordinated units. The distributiontotaling $7,819,000 was paid on August 15, 2005 to holders of recordat the close of business on August 1, 2005 and included 1,372,458 commonunits issued in connection with the closing of the ScissorTail Acquisition (discussedin Note 4). This distribution amount also included a concurrent quarterlydistribution of $0.495 per unit with respect to 4,830,758 Class B unitsissued in connection with the closing of the ScissorTail Acquisition. Pursuantto the terms of the Class B units, the holders of these units wereentitled to quarterly distributions equal to 110% of the quarterly distributionper unit to be received by the common units.

On October 17, 2005, the Board of Directorsdeclared a cash distribution for the three months ended September 30, 2005of $0.50 per unit for all outstanding common and subordinated units. Thedistribution totaling $8,449,000 will be paid on November 14, 2005 toholders of record at the close of business on November 1, 2005. Nodistributions are payable for the three months ended September 30, 2005with 

19

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 6—Members’Capital and Distributions (Continued)**

respectto Class B units since all outstanding Class B units were convertedto common units on October 27, 2005.

*Unit Options*

Unit options are granted under CE’s long-termincentive plan and have an exercise price that may not be less than the fairmarket value of the underlying units on the date of grant. In general, unitoptions granted will become exercisable over a period determined by theCompensation Committee. In addition, unit options will become exercisable upona change in control of CE, unless provided otherwise by the CompensationCommittee.

During the nine months ended September 30, 2005,CE granted 286,420 unit options to purchase an equal number of common units atan average exercise price of $36.39 per unit to officers and certain employees,including 169,002 options awarded at the time of the ScissorTail Acquisition toScissorTail employees. These unit options will vest in five equal annualinstallments commencing with the first anniversary of the grant date or willbecome exercisable upon a change of control, death or disability. Outstandingoptions have remaining contractual lives of approximately 10 years at September 30,2005.

Asummary of the unit option activity for the nine months ended September 30,2005 is provided below:

| ** **                                     | ** ** | **Number of  Units  Underlying  Options** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
|------------------------------------------------|------------|------------------------------------------------|------------|----------------------------------------|------------|
| Outstanding at  beginning of period            |       |                                           | 200,000    |                                   |       |   | $ | 20.00 |   |   |
| Granted                                        |       |                                           | 286,420    |                                   |       |   | 36.39 |   |   |
| Exercised                                      |       |                                           | —     |                                   |       |   | — |   |   |
| Forfeited                                      |       |                                           | (12,560    | )                                      |       |   | 27.61 |   |   |
| Outstanding at  end of period                  |       |                                           | 473,860    |                                   |       |   | $ | 29.71 |   |   |
| Exercisable at end of period                   |       |                                           | 4,138      |                                   |       |   | $ | 23.66 |   |   |
| Weighted average  fair value of option granted |       |                                           |       |                                   |       |   | $ | 3.62 |   |   |

 

*Accounting forStock-Based Compensation*

The Company uses the intrinsic value method establishedby APB No. 25, *“Accounting for Stock Issued to Employees”*to value unit options issued to employees under CE’s long-term incentive planadopted on November 15, 2004. In accordance with APB No. 25 for fixedunit options, compensation is recorded to the extent the fair value of the unitexceeds the exercise price of the option at the measurement date. Compensationcosts for fixed awards with pro rata vesting are recognized on a straight-linebasis over the vesting period. For the nine months ended September 30,2005, the cost of this stock-based compensation program had no impact on theCompany’s net income, as all options granted had an exercise price equal to themarket value of the underlying common unit on the date of grant.

20

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 6—Members’Capital and Distributions (Continued)**

If compensation expenserelated to the issuance of the options had been determined by applying the fairvalue method prescribed in SFAS No. 123, the Company’s net income and netincome per equivalent unit would have approximated the pro forma amounts below(in thousands):

| ** **                                                                          | ** ** | **Three Months Ended  September 30,** | ** ** | **Nine Months Ended  September 30,** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                          | ** ** | **   2005   **         | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Net income, as  reported                                                            |       |                                                 | $          | 5,159                                               |       |   | $ | 2,703 |   | $ | 16,100 |   | $ | 1,491 |   |
| Less: Stock-based  employee compensation expense determined under fair value method |       |                                                 | (155       | )                                                   |       | — |   | (250 | ) | — |   |
| Pro forma net  income                                                               |       |                                                 | $          | 5,004                                               |       |   | $ | 2,703 |   | $ | 15,850 |   | $ | 1,491 |   |
| Net income per  equivalent unit:                                                    |       |                                                 |       |                                                |       |   |   |   |   |   |   |
| Basic—as reported                                                              |       |                                                 | $          | 0.35                                                |       |   | $ | 1.90 |   | $ | 1.35 |   | $ | 1.05 |   |
| Basic—pro forma                                                                |       |                                                 | $          | 0.34                                                |       |   | $ | 1.90 |   | $ | 1.33 |   | $ | 1.05 |   |
| Diluted—as reported                                                            |       |                                                 | $          | 0.35                                                |       |   | $ | 0.98 |   | $ | 1.34 |   | $ | 1.05 |   |
| Diluted—pro forma                                                              |       |                                                 | $          | 0.34                                                |       |   | $ | 0.98 |   | $ | 1.32 |   | $ | 1.05 |   |

 

The effects of applying SFAS No. 123 in this proforma disclosure are not indicative of future amounts.

The fair value of eachunit option granted is estimated on the date of grant using the Black-Scholesoption-pricing model with the following assumptions for 2005 (no options weregranted during the nine months ended September 30, 2004): weighted averageexercise price of $36.39, expected volatility rate of 26.03%, risk-freeinterest rate of 4.14% and expected life of seven years. The Black-Scholesweighted average fair value of options granted in 2005 was $5.10 per unit.

**Note 7**—Net Income Per Unit

Basic net income per equivalent unit excludes dilutionand is computed by dividing net income attributable to the common unitholdersby the weighted average number of equivalent units outstanding during theperiod. Dilutive net income per equivalent unit reflects potential dilution andis computed by dividing net income attributable to the common unitholders bythe weighted average number of equivalent units outstanding during the periodincreased by the number of additional units that would have been outstanding ifthe dilutive potential units had been exercised.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 7**—Net Income Per Unit (Continued)

Basicnet income per equivalent unit is calculated as follows (in thousands, exceptper unit amounts). For periods prior to the Offering, equivalent units werecalculated using the weighted average of pre-Offering common units and commonspecial units adjusted by a conversion or exchange factor to reflect theexchange of pre-Offering common units and common special units forpost-Offering common units immediately prior to completion of the Offering.

| ** **                                                      | ** ** | **Three Months  Ended September 30,** | ** ** | **Nine Months  Ended September 30,** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                      | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Net income  available—basic                                |       | $                                                    | 5,159      |                                                | $          | 2,703 |   | $ | 16,100 |   | $ | 1,491 |   |
| Accretion of  preferred units                                   |       | —                                               |       | 426                                                 |       | — |   | — |   |
| Payment in kind distributions to pre-IPO preferred  unitholders |       | —                                               |       | 1,525                                               |       | — |   | — |   |
| Net income  available—diluted*                             |       | $                                                    | 5,159      |                                                | $          | 4,654 |   | $ | 16,100 |   | $ | 1,491 |   |
| Basic weighted average equivalent units                         |       | 14,556                                               |       | 1,426                                               |       | 11,943 |   | 1,426 |   |
| Dilutive weighted  average equivalent units*                    |       | 14,676                                               |       | 4,728                                               |       | 12,026 |   | 1,426 |   |
| Basic net income per equivalent unit                            |       | $                                                    | 0.35       |                                                | $          | 1.90 |   | $ | 1.35 |   | $ | 1.05 |   |
| Diluted net income per  equivalent unit*                        |       | $                                                    | 0.35       |                                                | $          | 0.98 |   | $ | 1.34 |   | $ | 1.05 |   |

----

*                    CE had 120,314and 82,138 potentially dilutive employee unit options outstanding during thethree and nine months ended September 30, 2005, respectively, and nopotentially dilutive restricted units outstanding during the three and ninemonths ended September 30, 2005. During the three and nine months ended September 30,2004, CE had 3,750,000 potentially dilutive warrants previously held bypre-Offering preferred unitholders and a subsidiary warrant that wasrepurchased in November 2004 outstanding. For the three and nine monthsended September 30, 2004, incremental units related to the subsidiarywarrant were not included in the dilutive income per unit because to do sowould have been anti-dilutive. For the nine months ended September 30,2004, incremental units related to the warrants previously held by pre-Offeringpreferred unitholders were not included because to do so would have beenanti-dilutive.

Net income per unit forthe three and nine months ended September 30, 2004 has not been presentedfor pre-Offering junior units and junior special units as such units were notentitled to share in earnings for this period.

**Note 8—RelatedParty Transactions**

*Operations Services*

Through December 31,2004, the Company did not directly employ any persons to manage or operate itsbusiness other than certain Delaware-based officers. With respect to the Texasoperating subsidiaries of the Company, Copano/Operations, Inc. (“CopanoOperations”), an entity controlled by John R. Eckel, Jr., Chairman of theBoard of Directors and Chief Executive Officer of the Company, providedmanagement, operations and administrative support services for the Company. TheCompany reimbursed Copano Operations for all direct and indirect costs of theseservices. Copano Operations charged these subsidiaries, without markup, basedupon total monthly expenses incurred by Copano Operations less (i) a 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 8—Related Party Transactions (Continued)**

fixedallocation to reflect expenses incurred by Copano Operations for the benefit ofcertain entities controlled by Mr. Eckel and (ii) any costs to becharged directly to an entity for which Copano Operations performed services. Managementbelieves that this methodology was reasonable. Effective January 1, 2005and pursuant to a general and administrative services agreement with CopanoOperations, Copano Operations transferred responsibility to CPNO Services,L.P., an indirect wholly owned subsidiary of CE, for a significant portion ofthe services, including its employment of certain employees on the Company’sbehalf, that Copano Operations had previously provided to the Company. Underthe general and administrative services agreement, the Company continues toreimburse Copano Operations for all direct and indirect costs of the servicesprovided to the Company by Copano Operations using the same methodology asutilized prior to January 1, 2005. Management believes that thismethodology is reasonable. For the three months ended September 30, 2005and 2004, the Company reimbursed Copano Operations $685,000 and $4,426,000,respectively, for administrative and operating costs, including payroll andbenefits expense for both field and administrative personnel of the Company. Forthe nine months ended September 30, 2005 and 2004, the Company reimbursedCopano Operations $2,218,000 and $11,745,000, respectively, for administrativeand operating costs, including payroll and benefits expense for both field andadministrative personnel of the Company. These costs are included in operationsand maintenance expenses and general and administrative expenses on theconsolidated statements of operations. As of September 30, 2005, amountspayable by the Company to Copano Operations were $44,000.

Management estimates thatthese expenses on a stand-alone basis (that is, the cost that would havebeen incurred by the Company to conduct current operations if the Company hadobtained these services from an unaffiliated entity) would not be significantlydifferent from the amounts recorded in the Company’s consolidated financialstatements for each of the three and nine months ended September 30, 2005and 2004.

*Natural Gas Transactions*

During the three monthsended September 30, 2005 and 2004, the Company purchased natural gas fromaffiliated companies of Mr. Eckel totaling $331,000 and $378,000,respectively, and provided gathering and compression services to affiliatedentities of Mr. Eckel totaling $7,000 and $18,000, respectively. Duringthe nine months ended September 30, 2005 and 2004, the Companypurchased natural gas from affiliated companies of Mr. Eckel totaling$857,000 and $1,141,000, respectively, and provided gathering and compressionservices to affiliated entities of Mr. Eckel totaling $23,000 and $59,000,respectively. Additionally, affiliated companies of Mr. Eckel reimbursedthe Company $20,000 and $14,000 for the three months ended September 30,2005 and 2004, respectively, and $63,000 and $38,000 for the nine months ended September 30,2005 and 2004, respectively, in gas lift costs which are reflected as areduction of operations and maintenance expense in the consolidated statementsof operations. Management believes these purchases and sales were on terms noless favorable than those that could have been achieved with an unaffiliatedentity. As of September 30, 2005, amounts payable by the Company toaffiliated companies of Mr. Eckel, other than Copano Operations, totaled$115,000.

Natural gas sales to WDG totaled $0 and $73,000 forthe three months ended September 30, 2005 and 2004, respectively, and$38,000 and $503,000 for the nine months ended September 30, 2005 and2004, respectively. Natural gas purchases and transportation costs from WDGtotaled $2,112,000 and $537,000 for the three months ended September 30,2005 and 2004, respectively. Natural gas purchases and 

23

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 8—Related Party Transactions (Continued)**

transportationcosts from WDG totaled $2,615,000 and $1,263,000 for the nine months ended September 30, 2005and 2004, respectively. Well connection fees paid to WDG totaled $67,000 forthe nine months ended September 30, 2005. Additionally, as operatorof WDG, a subsidiary of CE charges WDG a monthly administrative fee of $16,000and has made advances to WDG for capital expenditures. As of September 30,2005, the Company’s net payable to WDG totaled $411,000.

*Other*

Computer Group, Inc.,of which Mr. Wayne S. Harrison is President and majority shareholder,provided computer consulting services to the Company and its predecessors andaffiliates from the early 1980s until Mr. Harrison’s election as theCompany’s Vice President and Chief Information Officer in June 2005. From1996 through 2004, these services were provided through Copano Operations andthe expenses were included in the calculation of its charges to the Company. BeginningJanuary 2005, Computer Group, Inc.’s services were provided directlyto the Company and for the nine months ended September 30, 2005,associated expenses totaled $96,000. In connection with the transition by Mr. Harrisonfrom consultant to employee, he agreed to transfer to the Company anon-exclusive right to all software previously developed by Computer Group, Inc.and utilized by the Company or for its benefit for a purchase price of $24,000.Mr. Harrison also agreed to transfer a similar license to CopanoOperations for the same purchase price and for the benefit of, and at theexpense of, certain entities affiliated with Mr. Eckel.

Following the completionof the ScissorTail Acquisition, the Company paid, certain change of control liabilitiesthat were for the account of the pre-acquisition owners of ScissorTail as aresult of the net working capital adjustments to the purchase price ofScissorTail (Note 4). During August 2005, the Company paidapproximately $19,500,000 to five officers of ScissorTail that remainedemployed by ScissorTail following the acquisition.

**Note 9—Commitmentsand Contingencies**

*Commitments*

For the three months endedSeptember 30, 2005 and 2004, rental expense for office space, leasedvehicles and leased compressors and related field equipment used in the Company’soperations totaled $253,000 and $334,000, respectively. For the nine monthsended September 30, 2005 and 2004, rental expense for office space, leasedvehicles and leased compressors and related field equipment used in the Company’soperations totaled $735,000 and $1,307,000, respectively.

The Company has both fixed and variable quantitycontractual commitments arising in the ordinary course of its natural gasmarketing activities. At September 30, 2005, the Company had fixedcontractual commitments to purchase 6,118,625 million British thermalunits (“MMBtu”) of natural gas in October 2005. As of September 30,2005, the Company had fixed contractual commitments to sell6,427,075 MMBtu of natural gas in October 2005. All of thesecontracts are based on index-related market pricing. Using index-relatedmarket prices as of September 30, 2005, total commitments to purchasenatural gas related to such agreements equaled $51,993,000 and the totalcommitment to sell natural gas under such agreements equaled $71,280,000. TheCompany’s commitments to purchase variable quantities of natural gas at index-basedprices range from contract periods extending from one month to the life of thededicated production. During September 2005, natural gas volumes purchasedunder such contracts 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 9—Commitments and Contingencies (Continued)**

equaled8,679,621 MMBtu. The Company’s commitments to sell variable quantities ofnatural gas at index-based prices range from contract periods extendingfrom one month to 2012. During September 2005, natural gas volumes soldunder such contracts equaled 3,020,232 MMBtu.

*Guarantees*

In November 2002, the FASB issued FIN 45, “*Guarantor’s Accounting and Disclosure Requirements for Guarantees,Including Indirect Guarantees of Indebtedness of Others*.” In certaininstances, this interpretation requires a guarantor to recognize, at theinception of a guarantee, a liability for the fair value of the obligationundertaken in issuing the guarantee.

From July 8,2002 through April 1, 2004, the Company guaranteed certain vehicle leaseobligations of Copano Operations for vehicles operated for the benefit ofcertain of the Company’s operating entities. Effective as of April 2,2004, the vehicle leases were transferred by Copano Operations to CopanoPipelines/Hebbronville, L.P. (“Hebbronville”), an indirect wholly ownedsubsidiary of CE. Hebbronville, as lessee, guarantees the lessor a minimumresidual sales value upon the expiration of the lease and sale of theunderlying vehicle under the transferred leases and certain other vehicle leases.Certain of the Texas Gulf Coast Pipelines entities currently guarantee thelease payment obligations, including the residual sales value under thetransferred leases. As of September 30, 2005, certain subsidiaries of CEguaranteed $408,000 related to these lease payment obligations. As of September 30,2005, aggregate guaranteed residual values for vehicles under these operatingleases were as follows (in thousands):

| ** **             | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Lease residual  values |       |     | $          | 58       |       |     |       | $        | 36         |           |       |      | $          | 56 |   |   | $ | 126 |   |   | $ | — |   |   | $ | 276 |   |
|                        |            |          |            |          |            |          |            |          |            |                |            |           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Effective April 12, 2003, the Company hasguaranteed certain telephone equipment lease obligations (approximately $16,000of lease payment obligations as of September 30, 2005) of CopanoOperations. Prior to January 1, 2005, the use of this telephone equipmentby the Company was included in the support services provided by CopanoOperations to the Company. See Note 8.

Presently, neither the Company nor any of itssubsidiaries have any other types of guarantees outstanding that requireliability recognition under the provisions of FIN 45.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 9—Commitmentsand Contingencies (Continued)**

FIN 45 also sets forthdisclosure requirements for guarantees by a parent company on behalf of itssubsidiaries. CE or a subsidiary entity, from time to time, may issue parentguarantees of commitments resulting from the ongoing activities of subsidiaryentities. Additionally, a subsidiary entity may from time to time issue aguarantee of commitments resulting from the ongoing activities of anothersubsidiary entity. The guarantees generally arise in connection with asubsidiary commodity purchase obligation, subsidiary lease commitments orsubsidiary bank debt. The nature of such guarantees is to guarantee theperformance of the subsidiary entities in meeting their respective underlyingobligations. Except for operating lease commitments, all such underlyingobligations are recorded on the books of the subsidiary entities and areincluded in the consolidated financial statements as obligations of thecombined entities. Accordingly, such obligations are not recorded again on thebooks of the parent. The parent would only be called upon to perform under theguarantee in the event of a payment default by the applicable subsidiary entity.In satisfying such obligations, the parent would first look to the assets ofthe defaulting subsidiary entity. As of September 30, 2005, theapproximate amount of parental guaranteed obligations were as follows (inthousands):

| ** **           | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|----------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| Bank debt            |       | $        | —     |     |       | $        | —     |     |       |           | $          | —    |       |   |   | $ | — |   |   | $ | 402,000 |   | $ | 402,000 |   |
| Commodity  purchases |       | 4,700    |       |     | —     |     |       |     | —     |           |       |      | —     |   |   | — |   | 4,700 |   |
|                 |       | $        | 4,700      |     |       | $        | —     |     |       |           | $          | —    |       |   |   | $ | — |   |   | $ | 402,000 |   | $ | 406,700 |   |

 

*RegulatoryCompliance*

In the ordinary course ofbusiness, the Company is subject to various laws and regulations. In theopinion of management, compliance with existing laws and regulations will notmaterially affect the financial position of the Company.

*Litigation*

The Company is named as adefendant, from time to time, in litigation relating to its normal businessoperations. Management is not aware of any significant litigation, pending orthreatened, that would have a significant adverse effect on the Company’sfinancial position or results of operations.

**Note 10—Supplemental Disclosures to theStatements of Cash Flows**

*Cash paid during each of the periods presented (inthousands)*

| ** ** | ** ** | **Nine Months  Ended September 30,** | ** ** |
|------------|------------|-----------------------------------------------------|------------|
| ** ** | ** ** | **   2005   **        | ** ** | **2004** | ** ** |
| Interest   |       |                                                | $          | 3,164 |   |   | $ | 2,556 |   |
| Taxes      |       |                                                | —     |   |   | — |   |
|            |            |                                                     |            |  |  |  |  |  |  |

 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 10—SupplementalDisclosures to the Statements of Cash Flows (Continued)**

*Supplemental disclosures of noncash investing andfinancing activities (in thousands)*

| ** **                                                    | ** ** | **Nine Months  Ended September 30,** | ** ** |
|---------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                    | ** ** | **  2005  **                    | ** ** | **  2004  ** | ** ** |
| Decrease in  equity in earnings from unconsolidated affiliate |       |                                                | $          | 90 |   |   |   | $ | 90 |   |   |
| Decrease in  accounts receivable from affiliates              |       |                                                | (90        | ) |   |   | (90 | ) |   |
| Decrease in  senior debt                                      |       |                                                | —     |   |   |   | (395 | ) |   |
| Increase in property, plant and equipment                     |       |                                                | (198       | ) |   |   | (381 | ) |   |
| Increase in other  assets                                     |       |                                                | (51        | ) |   |   | — |   |   |
| Increase in  accounts payable                                 |       |                                                | 168        |   |   |   | — |   |   |
| Increase in other  current liabilities                        |       |                                                | 181        |   |   |   | — |   |   |
| Increase in other  noncurrent liabilities                     |       |                                                | —     |   |   |   | 776 |   |   |
| Increase in deferred  offering costs                          |       |                                                | (100       | ) |   |   | — |   |   |

 

**Note 11—Financial Instruments**

The Company is exposed tomarket risks, including changes in commodity prices and interest rates. TheCompany may use financial instruments such as puts, swaps, options and otherfinancial instruments with similar characteristics to mitigate the risks ofcertain identifiable and anticipated transactions consistent with its RiskManagement Policy. In general, the type of risks the Company attempts to hedgeare those related to the variability of future earnings, fair values of certaindebt instruments and cash flows resulting from changes in applicable commodityprices or interest rates. As a matter of policy, the Company does not usefinancial instruments for speculative (or “trading”) purposes.

*Commodity RiskHedging Program*

The prices of natural gas and NGLs are subject tofluctuations in response to changes in supply, market uncertainty and a varietyof additional factors that are beyond the Company’s control. In order to managethe risks associated with natural gas and NGLs, the Company engages in riskmanagement activities that take the form of commodity derivative instruments. These activities are governed by the Company’sRisk Management Policy, which prohibits speculative transactions and limits thetype, maturity and notional amounts of derivative transactions. The policyallows management to purchase crude oil and natural gas liquids puts andcertain natural gas put or call options in order to reduce its exposure to asubstantial adverse change in the prices of those commodities. The Company’sRisk Management Committee monitors and ensures compliance with the RiskManagement Policy and is comprised of senior level executives in theoperations, finance and legal departments. The Audit Committee of CE’s Board ofDirectors monitors the implementation of the policy and the Company has engagedan independent firm to provide additional oversight. The Risk Management Policyrequires derivative transactions to take place either on the New YorkMercantile Exchange (NYMEX) through a clearing member firm or with over thecounter counterparties with investment grade ratings from both Moody’s andStandard & Poor’s. Potential derivative transactions are analyzed toevaluate their efficacy within the risk management strategy.

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 11—FinancialInstruments (Continued)**

In late July 2005,the Company entered into put transactions for the sale of West TexasIntermediate crude oil with a combined notional amount of 60,000 barrels permonth for a term from September 2005 through December 2007. Thecounterparties have investment grade ratings. The derivatives are intended tohedge the risk of weakening NGL prices with offsetting increases in the valueof the puts based on the correlation between NGL prices and crude oil prices. TheCompany designated these two transactions as cash flow hedges under SFAS No. 133,“*Accounting for Derivative Instruments andHedging Activities*” (as amended and interpreted) effective October 25,2005. For the period ended September 30, 2005, the Company recorded a fairvalue loss against other revenue of $292,000 related to these put contracts. Asof September 30, 2005, the fair value of these contracts totaled$3,564,000.

In 2004, ScissorTailentered into certain derivative transactions on behalf of three suppliers fromwhom ScissorTail purchased a significant volume of natural gas. The arrangementwith the suppliers provided that any gains or losses that resulted from thederivative transactions passed through to the suppliers. ScissorTail’s creditexposure was guaranteed by the physical production from the three suppliers.The potential credit risk for each of the suppliers was evaluated on a regularbasis and the volume available to hedge was modified to match a percentage ofthe supplier’s actual volumes sold to ScissorTail. ScissorTail received a feeof $1,000 per month related to these transactions. ScissorTail did not and theCompany has not recorded any other revenue or expenses associated with thesederivative transactions. As of September 30, 2005, the Company hasrecorded a current asset and a current liability of $774,000 related to thesearrangements. In October 2005, all of the positions under these derivativetransactions expired.

*Interest Rate Risk Hedging Program*

The Company’s interestrate exposure results from variable rate borrowings under its debt agreements.The Company manages a portion of its interest rate exposure by utilizinginterest rate swaps, which allow the Company to convert a portion of variablerate debt into fixed rate debt.

In October 2005, theCompany entered into two interest rate swap agreements with an aggregatenotional amount of $50 million in which the Company exchanged the paymentof variable rate interest on a portion of the principal outstanding under theCredit Facility for fixed rate interest. The Company has designated these twointerest rate swaps as cash flow hedges under SFAS No. 133. Under eachswap agreement, the Company will pay the counterparties the fixed interest rateof approximately 4.7% monthly and will receive back from the counterparties avariable interest rate based on one-month LIBOR rates. The interest rate swapscover the period from October 2005 through July 2010 and thesettlement amounts will be recognized to earnings as either an increase or a decreasein interest expense.

**Note 12—Segment Information**

Based on the Company’s approach to managing itsassets, the Company believes its operations consist of four segments: (i) gathering,transportation and marketing of natural gas in the Texas Gulf Coast region(Texas Gulf Coast Pipelines), (ii) natural gas processing and related NGLtransportation in the Texas Gulf Coast region (Texas Gulf Coast Processing), (iii) naturalgas gathering and processing in Eastern and Central Oklahoma (Mid-ContinentOperations) and (iv) risk management and other corporate activities. TheCompany currently reports its operations, both internally and externally, usingthese four segments. The Company evaluates segment performance based on segmentmargin before depreciation and 

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**COPANO ENERGY, L.L.C. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (Continued)**

**Note 12—Segment Information (Continued)**

amortization.Through September 30, 2005, all of the Company’s revenue was derived from,and all of the Company assets and operations were located in, the Texas Gulf Coastand Mid-Continent regions of the United States. Transactions between reportablesegments are conducted on an arm’s length basis.

Summarized financialinformation concerning the Company’s reportable segments is shown in thefollowing table (in thousands):

| ** **                                                | ** **   | **Texas Gulf  Coast  Pipelines** | ** ** | **Texas Gulf  Coast  Processing** | ** ** | **Mid-  Continent  Operations** | ** ** | **Corporate** | ** ** | **Eliminations** | ** ** | **Total** | ** ** |
|-----------------------------------------------------------|--------------|---------------------------------------|------------|----------------------------------------|------------|---------------------------------|------------|---------------|------------|------------------|------------|-----------|------------|
| ***Three  Months Ended September 30, 2005:***        |         |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Sales to external customers                               |         |                                  | $          | 106,867                                |       |                            |       | $             | 39,203     |             |       |      | $          | 70,889 |   |   |   | $ | (292 | )(a) |   |   | $ | — |   |   | $ | 216,667 |   |
| Intersegment sales                                        |         |                                  | 51,725     |                                   |       |                            | 20,991     |          |       |             | —     |      |       |   | — |   |   |   | (72,716 | ) |   | — |   |
| Interest expense and other financing  costs               |         |                                  | 1,750      |                                   |       |                            | 184        |          |       |             | —     |      |       |   | 6,664 |   |   |   | (56 | ) |   | 8,542 |   |
| Depreciation and amortization                             |         |                                  | 1,346      |                                   |       |                            | 535        |          |       |             | 3,784      |      |       |   | 41 |   |   |   | — |   |   | 5,706 |   |
| Equity in (earnings) loss from unconsolidated  affiliates |         |                                  | (245       | )                                      |       |                            | —     |          |       |             | 5          |      |       |   | — |   |   |   | — |   |   | (240 | ) |
| Segment profit (loss)                                     |         |                                  | 2,225      |                                   |       |                            | 3,794      |          |       |             | 8,142      |      |       |   | (9,002 | ) |   |   | — |   |   | 5,159 |   |
| Capital expenditures                                      |         |                                  | 332        |                                   |       |                            | 435        |          |       |             | 482,943    |      |       |   | 441 |   |   |   | — |   |   | 484,151 |   |
| ***Three Months Ended  September 30, 2004:***        |         |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |   |   |   |   |   |   |
| Sales to external customers                               |         |                                  | $          | 75,566                                 |       |                            |       | $             | 45,229     |             |       |      | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 120,795 |   |
| Intersegment sales                                        |         |                                  | 39,108     |                                   |       |                            | 3,481      |          |       |             | —     |      |       |   | — |   |   |   | (42,589 | ) |   | — |   |
| Interest expense and other financing  costs               |         |                                  | 819        |                                   |       |                            | 587        |          |       |             | —     |      |       |   | 2,817 |   |   |   | (418 | ) |   | 3,805 |   |
| Depreciation and amortization                             |         |                                  | 1,295      |                                   |       |                            | 940        |          |       |             | —     |      |       |   | 17 |   |   |   | — |   |   | 2,252 |   |
| Equity in earnings from unconsolidated affiliate          |         |                                  | (96        | )                                      |       |                            | —     |          |       |             | —     |      |       |   | — |   |   |   | — |   |   | (96 | ) |
| Segment profit (loss)                                     |         |                                  | 2,889      |                                   |       |                            | 3,250      |          |       |             | —     |      |       |   | (3,436 | ) |   |   | — |   |   | 2,703 |   |
| Capital expenditures                                      |         |                                  | 2,312      |                                   |       |                            | 84         |          |       |             | —     |      |       |   | — |   |   |   | — |   |   | 2,396 |   |
| ***Nine Months Ended  September 30, 2005:***         | *** *** |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |   |   |   | ** ** | ** ** | ** ** |
| Sales to external customers                               |         |                                  | $          | 250,714                                |       |                            |       | $             | 131,328    |             |       |      | $          | 70,889 |   |   |   | $ | (292 | )(a) |   |   | $ | — |   |   | $ | 452,639 |   |
| Intersegment sales                                        |         |                                  | 131,608    |                                   |       |                            | 27,409     |          |       |             | —     |      |       |   | — |   |   |   | (159,017 | ) |   | — |   |
| Interest expense and other financing  costs               |         |                                  | 3,468      |                                   |       |                            | 456        |          |       |             | —     |      |       |   | 6,994 |   |   |   | (386 | ) |   | 10,532 |   |
| Depreciation and amortization                             |         |                                  | 3,905      |                                   |       |                            | 1,597      |          |       |             | 3,784      |      |       |   | 85 |   |   |   | — |   |   | 9,371 |   |
| Equity in (earnings) loss from unconsolidated  affiliates |         |                                  | (731       | )                                      |       |                            | —     |          |       |             | 5          |      |       |   | — |   |   |   | — |   |   | (726 | ) |
| Segment profit (loss)                                     |         |                                  | 8,605      |                                   |       |                            | 11,477     |          |       |             | 8,142      |      |       |   | (12,124 | ) |   |   | — |   |   | 16,100 |   |
| Segment assets                                            |         |                                  | 165,559    |                                   |       |                            | 82,823     |          |       |             | 567,577    |      |       |   | 11,954 |   |   |   | (52,360 | ) |   | 775,553 |   |
| Capital expenditures                                      |         |                                  | 2,593      |                                   |       |                            | 775        |          |       |             | 482,944    |      |       |   | 1,356 |   |   |   | — |   |   | 487,668 |   |
| ***Nine Months Ended  September 30, 2004:***         | ** **   |                                  |       |                                   |       |                            |       |          |       |             |       |      |       |   |   |   |   |   |   |   | ** ** | ** ** | ** ** |
| Sales to external customers                               |         |                                  | $          | 204,955                                |       |                            |       | $             | 112,360    |             |       |      | $          | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 317,315 |   |
| Intersegment sales                                        |         |                                  | 103,852    |                                   |       |                            | 13,161     |          |       |             | —     |      |       |   | — |   |   |   | (117,013 | ) |   | — |   |
| Interest expense and other financing  costs               |         |                                  | 2,115      |                                   |       |                            | 2,438      |          |       |             | —     |      |       |   | 7,404 |   |   |   | (418 | ) |   | 11,539 |   |
| Depreciation and amortization                             |         |                                  | 3,581      |                                   |       |                            | 1,868      |          |       |             | —     |      |       |   | 49 |   |   |   | — |   |   | 5,498 |   |
| Equity in earnings in consolidated  affiliate             |         |                                  | (263       | )                                      |       |                            | —     |          |       |             | —     |      |       |   | — |   |   |   | — |   |   | (263 | ) |
| Segment profit (loss)                                     |         |                                  | 8,171      |                                   |       |                            | 1,773      |          |       |             | —     |      |       |   | (8,453 | ) |   |   | — |   |   | 1,491 |   |
| Capital  expenditures                                     |         |                                  | 5,918      |                                   |       |                            | 606        |          |       |             | —     |      |       |   | — |   |   |   | — |   |   | 6,524 |   |

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(a)     Representsthe results of risk management activities related to the Company’s puttransactions for the sale of West Texas Intermediate crude oil (Note 11).

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations.

*You should read thefollowing discussion of our financial condition and results of operations inconjunction with the unaudited consolidated financial statements and notesthereto included elsewhere in this report. References in this Item 2 to “CopanoEnergy, L.L.C.,” “we,” “our,” “us,” or like terms refer to Copano Energy,L.L.C. and its consolidated subsidiaries.*

*As generally used in the energy industry and in thisreport, the following terms have the following meanings:*
| *Bbls/d:*     | * * | *B**arrels per day*                                                                                                                       |
|---------------|----------|-------------------------------------------------------------------------------------------------------------------------------------------|
| *Btu:*        | * * | *British thermal units*                                                                                                                   |
| *MMBtu:*      | * * | *One million British thermal units*                                                                                                       |
| *MMBtu/d:*    | * * | *One million British thermal units per day*                                                                                               |
| *Mcf/d*       | * * | *One thousand cubic feet per day*                                                                                                         |
| *MMcf/d:*     | * * | *One million cubic feet per day*                                                                                                          |
| *NGLs:*       | * * | *Natural gas liquids, which consist primarily of  ethane, propane, isobutane, normal butane, natural gasoline and stabilized  condensate* |
| *throughput:* | * * | *The volume of product transported or passing  through a pipeline, plant, terminal or other facility*                                     |

 

***Overview***

We are a Delaware limited liability company formed in2001 to acquire entities operating under the Copano name since 1992 and toserve as a holding company for our operating subsidiaries. On November 15,2004, we completed our initial public offering of 5,750,000 common units at aprice of $20.00 per unit, inclusive of 750,000 common units which were issuedas a result of the underwriters’ exercise of their over-allotment option. Netproceeds from the sale of the units totaled $106.95 million.

On August 1,2005, we acquired all the membership interests in Tulsa-based ScissorTail for$499.1 million in cash, which reflected estimated net working capitaladjustments, due diligence and closing costs. ScissorTail’s assets are locatedin Central and Eastern Oklahoma and primarily consist of approximately 3,330miles of gathering pipelines and three processing plants with currentprocessing capacity of approximately 100 MMcf/d. In connection with the ScissorTail Acquisition, we, through ScissorTail,now operate and hold a majority interest in Southern Dome in partnership withthe prior ScissorTail ownership group. Southern Dome was formed to engage inthe midstream gas gathering and processing business and related operations in OklahomaCounty, Oklahoma. We financed the ScissorTail Acquisition and relatedcosts with:

·       Borrowingsof approximately $179.0 million of the $232.0 million initiallyborrowed under our new Credit Facility discussed in “—Liquidity and CapitalResources—Our Indebtedness”;

·       Borrowingsof $170.0 million borrowed under the Term Loan Facility discussed in “—Liquidityand Capital Resources—Our Indebtedness”; and

·       Netproceeds from a $174.0 million private placement of equity to certaininstitutional investors discussed in Note 6 of the unaudited consolidatedfinancial statements.

We manage our business and analyze and report ourresults of operations on a segment basis. Our operations are divided into fourbusiness segments, Texas Gulf Coast Pipelines, Texas Gulf Coast Processing,Mid-Continent Operations and Corporate.

·       *Texas Gulf Coast Pipelines* owns networksof natural gas gathering and intrastate pipelines in the Texas Gulf Coastregion and is engaged in the gathering and intrastate transmission of naturalgas in areas we sometimes refer to as the South Texas, Coastal Waters, CentralGulf Coast and Upper Gulf Coast regions. Within this segment, we also providecertain related services including 

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compression, dehydrationand marketing of natural gas. For the three months ended September 30,2005 and 2004, this segment generated approximately 27% and 51%, respectively,of our total gross margin. For the nine months ended September 30, 2005and 2004, this segment generated approximately 40% and 63%, respectively, ofour total gross margin.

·       *Texas Gulf Coast Processing* is engaged innatural gas processing, conditioning and treating and NGL fractionation andtransportation through our Houston Central Processing Plant and Sheridan NGLPipeline. Our natural gas processing plant is the second largest in the TexasGulf Coast region and the third largest in Texas in terms of throughputcapacity. The plant is located approximately 100 miles southwest of Houston,Texas. For the three months ended September 30, 2005 and 2004, thissegment generated approximately 24% and 49%, respectively, of our total grossmargin. For the nine months ended September 30, 2005 and 2004, thissegment generated approximately 35% and 37%, respectively, of our total grossmargin.

·       *Mid-Continent Operations*is a provider of natural gasmidstream services in Central and Eastern Oklahoma, including natural gas gatheringand related compression and dehydration services and natural gas processing. Forthe three months ended September 30, 2005 and 2004, this segment generatedapproximately 50% and 0%, respectively, of our total gross margin, whichincluded operations from August 1, 2005 through September 30, 2005. Forthe nine months ended September 30, 2005 and 2004, this segment generatedapproximately 25% and 0%, respectively, of our total gross margin whichincluded operations from August 1, 2005 through September 30, 2005.

·       *Corporate* engages in risk management and other corporate activities. Forthe three and nine months ended September 30, 2005 and 2004, this segmentgenerated approximately (1%) and 0%, respectively, of our total gross margin.

Total gross margin is a non-GAAP financial measure. Fora reconciliation of total gross margin to its most directly comparable GAAPmeasure, please read “—Non-GAAP Financial Measures.”

Our segment gross margins are determined primarily byfour interrelated variables: (1) the volume of natural gas gathered ortransported through our pipelines, (2) the volume of natural gasprocessed, conditioned or treated at our Houston Central Processing Plant andthe three processing plants operated by our Mid-Continent Operations segment, (3) thelevel and relationship of natural gas and NGL prices and (4) our currentcontract portfolio. Because our profitability is a function of the differencebetween the revenues we receive from our operations, including revenues fromthe products we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio and the pricingenvironment for natural gas and NGLs will dictate increases or decreases in ourprofitability. Our profitability is also dependent upon prices and marketdemand for natural gas and NGLs, which fluctuate with changes in market andeconomic conditions and other factors.

The margins we realizefrom a significant portion of the natural gas is gathered or transport by TexasGulf Coast Pipelines decreases in periods of low natural gas prices because ourunit margins on such natural gas volumes are based on a percentage of the indexprice. The profitability of Texas Gulf Coast Processing is dependent upon therelationship between natural gas and NGL prices. When natural gas prices arelow relative to NGL prices, it is more profitable for Texas Gulf CoastProcessing to process natural gas than to condition it. Conversely, whennatural gas prices are high relative to NGL prices, processing is lessprofitable or unprofitable. During such periods, our Houston Central ProcessingPlant has the flexibility to condition natural gas rather than fully process it.Conditioning natural gas, however, is less profitable than processing duringperiods when the value of recovered NGLs exceeds the value of natural gasrequired for plant fuel and to replace the reduced Btus that result fromprocessing the natural 

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gas. Mid-ContinentOperations’ margins are, on the whole, positively correlated with NGL pricesand are not materially impacted by changes in natural gas prices.

***How We Evaluate Our Operations***

We believe that investors benefit from having accessto the same financial measures that our management uses in evaluating ourperformance. Our management uses a variety of financial and operationalmeasurements to analyze our performance. These measurements include thefollowing: (1) throughput volumes, (2) segment gross margin, (3) operationsand maintenance expenses, (4) general and administrative expenses, (5) EBITDAand (6) distributable cash flow.

*ThroughputVolumes.**  *Throughputvolumes associated with our business are an important part of our operationalanalysis. We continually evaluate volumes on our pipelines to ensure that wehave adequate throughput to meet our financial objectives. It is important thatwe continually add new volumes to our gathering systems to offset or exceed thenormal decline of existing volumes that are attached to those systems. Ourperformance at our processing plants is significantly influenced by both thevolume of natural gas coming into the plant and the NGL content of the naturalgas. In addition, we monitor fuel consumption because it has a significantimpact on the gross margin realized from our processing or conditioningoperations. Although we monitor fuel costs associated with our pipelineoperations, these costs are frequently passed on to our producers.

*SegmentGross Margin.**  *Wedefine segment gross margin as our revenue minus cost of sales. Cost of salesincludes the following costs and expenses: cost of natural gas and NGLs purchasedby us from third parties, cost of natural gas and NGLs purchased by us fromaffiliates, costs we pay third parties to transport our volumes and costs wepay our affiliates to transport our volumes. We view segment gross margin as animportant performance measure of the core profitability of our operations. Thesegment gross margin data reflect the financial impact on our company of ourcontract portfolio. With respect to our Texas Gulf Coast Pipelines segment, ourmanagement analyzes segment gross margin per unit of volumes gathered ortransported. With respect to our Texas Gulf Coast Processing segment, ourmanagement also analyzes segment gross margin per unit of natural gas processedor conditioned and the segment gross margin per unit of NGLs recovered. Withrespect to our Mid-Continent Operations segment, our management analyzessegment gross margin per unit on volumes gathered or transported, per unit ofnatural gas processed and per unit of NGLs recovered. Our segment gross marginis reviewed monthly for consistency and trend analysis.

To isolate and consistently track changes in commodityprice relationships and their impact on our Texas Gulf Coast Processing segment’sresults, we calculate a hypothetical “standardized” processing margin. This processingmargin is based on a fixed set of assumptions, with respect to liquidscomposition and fuel consumption per recovered gallon, which we believe isgenerally reflective of our business. Because these assumptions are held stableover time, changes in underlying natural gas and NGL prices drive changes inthe standardized processing margin. Our financial results are not derived fromthis standardized processing margin and the standardized margin is not derivedfrom our financial results. However, we believe this calculation isrepresentative of the current operating commodity price environment of TexasGulf Coast Processing and we use this calculation to track commodity pricerelationships. Our results of operations may not necessarily correlate to the changesin our standardized processing margin because of the impact of factors otherthan commodity prices such as volumes, changes in NGL composition, recoveryrates and variable contract terms. Our standardized processing margins averaged$0.07 per gallon during the third quarter of 2005 compared to $0.13 per gallonduring the third quarter of 2004. Our standardized processing margins averaged$0.10 per gallon during the nine months ended September 30, 2005 comparedto $0.08 per gallon during the nine months ended September 30, 2004. Theaverage standardized processing margin for the period from 1989 through September 30,2005 is $0.09 per gallon.

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*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses are costsassociated with the operations of a specific asset. Direct labor, insurance, advalorem taxes, repair and maintenance, utilities and contract services comprisethe most significant portion of operations and maintenance expenses. Theseexpenses remain relatively stable across broad volume ranges and fluctuateslightly depending on the activities performed during a specific period. Aportion of our operations and maintenance expenses are incurred through CopanoOperations, an affiliate of our company. Under the terms of our arrangement withCopano Operations, we will reimburse it, at cost, for the operations andmaintenance expenses it incurs on our behalf. Effective January 1, 2005and pursuant to our general and administrative services agreement with CopanoOperations, Copano Operations transferred responsibility to us for asignificant portion of the services, including certain operating andmaintenance services, that it had previously provided to us.

*Generaland Administrative Expenses.**  *Our general and administrative expenses include thecost of employee and officer compensation and related benefits, office leaseand expenses, professional fees, information technology expenses, as well asother expenses not directly associated with our field operations. Substantiallyall of our general and administrative expenses were incurred through CopanoOperations, an affiliate of our company, through December 31, 2004. EffectiveJanuary 1, 2005 and pursuant to our general and administrative servicesagreement with Copano Operations, Copano Operations transferred responsibilityto us for a significant portion of the services, including certain general andadministrative services, that it had previously provided to us.

Pursuant to our limitedliability company agreement, our Pre-Offering Investors have agreed toreimburse us for our general and administrative expenses in excess of statedlevels (subject to certain limitations discussed below) for a period of threeyears beginning on January 1, 2005. Specifically, to the extent ourgeneral and administrative expenses exceed the following levels, the portion ofthe general and administrative expenses ultimately funded by us (subject tocertain adjustments and exclusions) will be limited, or capped, as indicated:

|   | **Year** | ** **                 | *** *** | **General and Administrative Expense  Limitations** |
|---|----------|----------------------------|--------------|-----------------------------------------------------|
| 1 |     | $1.50  million per quarter |
| 2 |     | $1.65  million per quarter |
| 3 |     | $1.80 million per  quarter |

 

During this three-year period, the quarterlylimitation on general and administrative expenses will be increased by 10% ofthe amount by which EBITDA (as defined below) for any quarter exceeds $5.4million. Additionally, the cap may beextended beyond its initial three-year term at the same or a higher level bythe affirmative vote of at least 95% of the common and subordinated units heldby our Pre-Offering Investors or their assignees, voting together as a singleclass. We can provide no assurance as to any such extension, as suchdetermination will be made in the sole discretion of our Pre-Offering Investors.This cap on general and administrative expenses excludes non-cashexpenses as well as expenses we may incur in connection with potentialacquisitions and capital improvements.

Immediately prior to completion of the Offering, wedistributed to our Pre-Offering Investors $4 million (the “Initial EscrowAmount”). Our Pre-Offering Investors deposited these funds in escrow accountsto be used for the purpose of satisfying their respective general andadministrative expense reimbursement obligation. Pursuant to our limited liabilitycompany agreement, upon exhaustion of the Original Escrow Amount, any furtherreimbursement obligation is limited solely to the amount of the distributionsattributable to the 5,557,378 common and subordinated units owned by thePre-Offering Investors immediately prior to our Offering (the “Pre-OfferingUnits”). In order to facilitate the payment of any further reimbursementobligation, our limited liability company agreement provides that we maydeposit any distributions that are required to cover the obligation and areotherwise payable to our Pre-

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Offering Investors,directly in the Pre-Offering Investors’ escrow accounts. Also, to the extentthat any of our Pre-Offering Investors sell Pre-Offering Units, the buyer mustassume the related reimbursement obligations or the selling Pre-OfferingInvestor must deposit certain funds in its escrow account to secure the paymentof any future reimbursement obligation with respect to the units transferred.On May 12, 2005, August 12, 2005 and November 10, 2005, Pre-Offering Investorsmade capital contributions to us in the aggregate amounts of $1.4 million, $1.2 millionand $1.5 million, respectively, as reimbursement of excess general andadministrative expenses for each of the three months ended March 31, 2005, June30, 2005 and September 30, 2005, respectively. As a result, the Initial EscrowAmount has been exhausted. We believe that our ability to deposit distributionsrequired to satisfy Pre-Offering Investors’ reimbursement obligations directlyin escrow together with the escrow requirements relating to the sale of anyPre-Offering Units provides us with additional assurance that our Pre-OfferingInvestors will be able to satisfy their respective reimbursement obligationswith respect to the Pre-Offering Units.

*EBITDA.**  *We define EBITDA as net income(loss) plus interest expense, provision for income taxes and depreciation andamortization expense. EBITDA is used as a supplemental financial measure by ourmanagement and by external users of our financial statements such as investors,commercial banks, research analysts and others, to assess:

·       thefinancial performance of our assets without regard to financing methods,capital structure or historical cost basis;

·       theability of our assets to generate cash sufficient to pay interest costs andsupport our indebtedness;

·       ouroperating performance and return on capital as compared to those of othercompanies in the midstream energy sector, without regard to financing orcapital structure; and

·       theviability of acquisitions and capital expenditure projects and the overallrates of return on alternative investment opportunities.

EBITDA is also a financial measurement that, withcertain negotiated adjustments, is reported to our lenders and is used tocompute our financial covenants under our credit facilities. EBITDA should notbe considered an alternative to net income, operating income, cash flows fromoperating activities or any other measure of financial performance presented inaccordance with GAAP.

*Distributable Cash Flow:**  *We define distributable cash flowas net income or loss plus: (1) depreciation and amortization expense; (2) cashdistributions received from investments in unconsolidated affiliates lessequity in the earnings of such unconsolidated affiliates; (3) reimbursementsby our Pre-Offering Investors of certain general and administrative expenses inexcess of the “G&A Cap” defined in our limited liability company agreement;(4) the subtraction of maintenance capital expenditures; and (5) theaddition of losses or subtraction of gains relating to other miscellaneousnon-cash amounts affecting net income for the period. Maintenance capitalexpenditures represent capital expenditures employedto replace partially or fully depreciated assets to maintain the existing operatingcapacity of our assets and to extend their useful lives, or other capitalexpenditures that are incurred in maintaining existing system volumes andrelated cash flows. Distributable cash flow is a significant performance metricused by senior management to compare basic cash flows generated by us (prior tothe establishment of any retained cash reserves by our board of directors) tothe cash distributions we expect to pay our unitholders. Using this metric,management can quickly compute the coverage ratio of estimated cash flows toplanned cash distributions. Distributable cash flow is also an importantnon-GAAP financial measure for our unitholders since it serves as an indicatorof our success in providing a cash return on investment. Specifically, thisfinancial measure indicates to investors whether or not we are generating cashflow at a level that can sustain or support an increase in our quarterlydistribution rates. Distributable cash flow is also a quantitative standardused throughout the investment community with respect to 

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publicly-tradedpartnerships and limited liability companies because the value of a unit ofsuch an entity is generally determined by the unit’s yield (which in turn isbased on the amount of cash distributions the entity can pay to an unitholder).

***How We Manage Our Operations***

Our management team uses a variety of tools to manageour business. These tools include: (i) our economic models; (ii) flowand transaction monitoring systems; (iii) producer activity evaluation andreporting; and (iv) imbalance monitoring and control.

*OurEconomic Models.**  *Weutilize our economic models to determine (i) whether we should process orcondition natural gas at our Houston Central Processing Plant, (ii) whetherwe should elect payment under certain Mid-Continent Operations’ “switch”contracts using a percentage-of-index basis or a percentage-of-proceeds basisand (iii) whether we should reduce the ethane extracted from certainnatural gas processed by our Mid-Continent Operations.

*Flowand Transaction Monitoring Systems.**  *We utilize proprietary systems thattrack commercial activity on our pipelines and monitor the flow of natural gason our pipelines. For example, we designed and implemented software that tracksour natural gas transactions, which allows us to continuously track volumes,pricing, imbalances and estimated revenues from our pipeline assets. Additionally,we designed and installed a Supervisory Control and Data Acquisition (SCADA)system, which assists management in monitoring and operating our pipeline systems.The SCADA system allows us to monitor our assets at remote locations andrespond to changes in pipeline operating conditions from our corporate office.

*ProducerActivity Evaluation and Reporting.**  *We monitor the producer drillingand completion activity in our areas of operation to identify anticipatedchanges in production and potential new well attachment opportunities. Thecontinued attachment of natural gas production to our pipeline systems iscritical to our business and directly impacts our financial performance. Usinga third-party electronic reporting system, we receive daily reports of newdrilling permits and completion reports filed with the state regulatory agencythat governs these activities. Additionally, our field personnel report thelocations of new wells in their respective areas and anticipated changes inproduction volumes to supply representatives and operating personnel at ourcorporate office. These processes enhance our awareness of new well activity inour operating areas and allow us to be responsive to producers in connectingnew volumes of natural gas to our pipelines.

*Imbalance Monitoring andControl.**  *Wecontinually monitor volumes received and volumes delivered on behalf of thirdparties to ensure we remain within acceptable imbalance limits during thecalendar month. We seek to reduce imbalances because of the inherent commodityprice risk that results when receipts and deliveries of natural gas are notbalanced concurrently. We have implemented “cash-out” provisions in many of ourtransportation agreements to reduce this commodity price risk. Cash-outprovisions require that any imbalance that exists between a third party and usat the end of a calendar month is settled in cash based upon a pre-determinedpricing formula. This provision ensures that imbalances under such contractsare not carried forward from month-to-month and revalued at higher or lowerprices.

***Our Growth Strategy***

Our growth strategy contemplates complementaryacquisitions of midstream assets in our operating areas as well as capitalexpenditures to enhance our ability to increase cash flows from our existingassets. We intend to pursue acquisitions and capital expenditure projects thatwe believe will allow us to capitalize on our existing infrastructure,personnel and relationships with producers and customers to provide midstreamservices. We also pursue selected acquisitions in new geographic areas to theextent they provide business opportunities similar to those in our existingareas of operations. To successfully execute 

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our growth strategy, wewill require access to capital on competitive terms. We believe that we willhave a lower cost of capital than many of our competitors that are masterlimited partnerships, or MLPs, because, unlike in a traditional MLP structure,neither our management nor any other party holds incentive distribution rightsthat entitle them to increasing percentages of cash distributions as higher perunit levels of cash distributions are received. We intend to finance futureacquisitions primarily by using the capacity available under our bank creditfacilities and equity or debt offerings or a combination of both. For a moredetailed discussion of our capital resources, please read “—Liquidity andCapital Resources.”

*AcquisitionAnalysis.**  *Inanalyzing a particular acquisition, we consider the operational, financial andstrategic benefits of the transaction. Our analysis includes location of theassets, strategic fit of the asset in relation to our business strategy,expertise required to manage the asset, capital required to integrate andmaintain the asset and the competitive environment of the area where the assetsare located. From a financial perspective, we analyze the rate of return theassets will generate under various case scenarios, comparative marketparameters and the additive earnings and cash flow capabilities of the assets.

*Capital ExpenditureAnalysis.**  *Wemake capital expenditures either to maintain our assets or the supply ofnatural gas volumes to our assets or for expansion projects to increase ourgross margin. Maintenance capital expenditures are capital expendituresemployed to replace partially or fully depreciated assets to maintain theexisting operating capacity of our assets and to extend their useful lives orother capital expenditures that are incurred in maintaining existing systemvolumes and related cash flows. Expansion capital expenditures representcapital expenditures made to expand or increase the efficiency of the existingoperating capacity of our assets. Expansion capital expenditures includeexpenditures that facilitate an increase in volumes within our operations,whether through construction or acquisition. Expenditures that reduce ouroperating costs will be considered expansion capital expenditures only if thereduction in operating expenses exceeds cost reductions typically resultingfrom routine maintenance. Our decisions whether to spend capital on expansionprojects are generally based on anticipated earnings, cash flow and rate ofreturn of the assets.

***Forward-Looking Statements***

This reportcontains certain “forward-looking statements” within the meaning of the federalsecurities laws. All statements, other than statements of historical factincluded in this report, including, but not limited to, those under “—OurResults of Operations” and “—Liquidity and Capital Resources” areforward-looking statements. Statementsincluded in this report that are not historical facts, that address activities,events or developments that we expect or anticipate will or may occur in thefuture, including things such as plans for growth of the business, futurecapital expenditures, competitive strengths, goals, references to future goalsor intentions or other such references are forward-looking statements. Thesestatements can be identified by the use of forward-looking terminologyincluding “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” orsimilar words. These statements are made by us based on our past experience andour perception of historical trends, current conditions and expected futuredevelopments as well as other considerations we believe are appropriate underthe circumstances. Whether actual results and developments in the future willconform to our expectations is subject to numerous risks and uncertainties,many of which are beyond our control. Therefore, actual outcomes andresults could materially differ from what is expressed, implied or forecast inthese statements. Any differences could be caused by a number of factors,including, but not limited to:

·       Ourability to successfully purchase and integrate any future acquired assets oroperations;

·       Thevolatility of prices and market demand for natural gas and natural gas liquids;

·       Ourability to continue to obtain new sources of natural gas supply;

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·       Theability of key producers to continue to drill and successfully complete andattach new natural gas supplies;

·       Ourability to retain our key customers;

·       Generaleconomic conditions;

·       Theeffects of government regulations and policies; and

·       Otherfinancial, operations and legal risks and uncertainties detailed from time totime in our filings with the Securities and Exchange Commission.

Cautionary statements identifying important factorsthat could cause actual results to differ materially from our expectations areset forth in this report, including without limitation in conjunction with theforward-looking statements that are referred to above. When consideringforward-looking statements, you should keep in mind the risk factors and othercautionary statements set forth in our Annual Report on Form 10-Kfor the year ended December 31, 2004 and in this report in “Management’sDiscussion and Analysis of Financial Condition and Results of Operations.” Allforward-looking statements included in this report and all subsequent writtenor oral forward-looking statements attributable to us or persons acting on ourbehalf are expressly qualified in their entirety by these cautionary statements.The forward-looking statements speak only as of the date made, other than asrequired by law, and we undertake no obligation to publicly update or reviseany forward-looking statements, whether as a result of new information, futureevents or otherwise.

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***Our Results ofOperations***

| ** **                                              | ** ** | **Three Months  Ended September 30,** | ** ** | **Nine Months  Ended September 30,** | ** ** |
|---------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                              | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                              | ** ** | **($ in thousands)**                       | ** ** |
| Total gross margin(1)                                   |       | $                                                    | 29,523     |                                                | $          | 14,459 |   | $ | 58,381 |   | $ | 34,005 |   |
| Operations and maintenance expenses                     |       | 5,325                                                |       | 3,186                                               |       | 11,302 |   | 9,155 |   |
| Depreciation and amortization                           |       | 5,706                                                |       | 2,252                                               |       | 9,371 |   | 5,498 |   |
| General and administrative expenses                     |       | 4,878                                                |       | 2,387                                               |       | 11,408 |   | 5,884 |   |
| Taxes other than income                                 |       | 321                                                  |       | 247                                                 |       | 713 |   | 748 |   |
| Equity in earnings from unconsolidated affiliates       |       | (240                                                 | )          | (96                                                 | )          | (726 | ) | (263 | ) |
| Operating income                                        |       | 13,533                                               |       | 6,483                                               |       | 26,313 |   | 12,983 |   |
| Interest and other income                               |       | 168                                                  |       | 25                                                  |       | 319 |   | 47 |   |
| Interest and other financing costs                      |       | (8,542                                               | )          | (3,805                                              | )          | (10,532 | ) | (11,539 | ) |
| Net income                                              |       | $                                                    | 5,159      |                                                | $          | 2,703 |   | $ | 16,100 |   | $ | 1,491 |   |
| Segment gross  margin:                                  |       |                                                 |       |                                                |       |   |   |   |   |
| Texas Gulf Coast Pipelines(2)                           |       | $                                                    | 7,948      |                                                | $          | 7,363 |   | $ | 23,337 |   | $ | 21,397 |   |
| Texas Gulf Coast Processing                             |       | 7,016                                                |       | 7,096                                               |       | 20,485 |   | 12,608 |   |
| Mid-Continent Operations(4)                             |       | 14,851                                               |       | —                                              |       | 14,851 |   | — |   |
| Corporate                                               |       | (292                                                 | )          | —                                              |       | (292 | ) | — |   |
| Total gross margin(1)                                   |       | $                                                    | 29,523     |                                                | $          | 14,459 |   | $ | 58,381 |   | $ | 34,005 |   |
| Segment gross  margin per unit:                         |       |                                                 |       |                                                |       |   |   |   |   |
| Texas Gulf Coast Pipelines ($/MMBtu)(2)                 |       | $                                                    | 0.36       |                                                | $          | 0.35 |   | $ | 0.37 |   | $ | 0.34 |   |
| Texas  Gulf Coast Processing:                           |       |                                                 |       |                                                |       |   |   |   |   |
| Inlet throughput ($/MMBtu)(3)                           |       | $                                                    | 0.14       |                                                | $          | 0.14 |   | $ | 0.13 |   | $ | 0.08 |   |
| NGLs produced ($/Bbl)(3)                                |       | $                                                    | 8.09       |                                                | $          | 4.66 |   | $ | 5.48 |   | $ | 3.04 |   |
| Mid-Continent  Operations(4)                            |       |                                                 |       |                                                |       |   |   |   |   |
| Pipeline throughput ($/MMBtu)(4)                        |       | $                                                    | 1.57       |                                                | $          | — |   | $ | 1.57 |   | $ | — |   |
| Plant Inlet throughput ($/MMBtu)(4)                     |       | $                                                    | 2.37       |                                                | $          | — |   | $ | 2.37 |   | $ | — |   |
| NGLs produced ($/Bbl)(4)                                |       | $                                                    | 28.13      |                                                | $          | — |   | $ | 28.13 |   | $ | — |   |
| Volumes:                                                |       |                                                 |       |                                                |       |   |   |   |   |
| Texas Gulf Coast Pipelines—throughput (MMBtu/d)(2) |       | 236,915                                              |       | 234,948                                             |       | 230,150 |   | 238,493 |   |
| Texas  Gulf Coast Processing:                           |       |                                                 |       |                                                |       |   |   |   |   |
| Inlet throughput (MMBtu/d)                              |       | 555,610                                              |       | 551,226                                             |       | 561,609 |   | 564,706 |   |
| NGLs produced (Bbls/d)                                  |       | 9,422                                                |       | 16,558                                              |       | 13,661 |   | 15,161 |   |
| Mid-Continent  Operations(4)                            |       |                                                 |       |                                                |       |   |   |   |   |
| Pipeline throughput (MMBtu/d)(4)                        |       | 155,153                                              |       | —                                              |       | 155,153 |   | — |   |
| Plant Inlet throughput (MMBtu/d)(4)                     |       | 102,706                                              |       | —                                              |       | 102,706 |   | — |   |
| NGLs produced (Bbls/d)(4)                               |       | 8,656                                                |       | —                                              |       | 8,656 |   | — |   |
| Maintenance capital expenditures                        |       | $                                                    | 1,400      |                                                | $          | 115 |   | $ | 2,795 |   | $ | 1,231 |   |
| Expansion capital expenditures                          |       | 482,751                                              |       | 2,281                                               |       | 484,873 |   | 5,293 |   |
| Total capital expenditures                              |       | $                                                    | 484,151    |                                                | $          | 2,396 |   | $ | 487,668 |   | $ | 6,524 |   |
| Operations and  maintenance expenses:                   |       |                                                 |       |                                                |       |   |   |   |   |
| Texas Gulf Coast Pipelines                              |       | $                                                    | 1,354      |                                                | $          | 1,460 |   | $ | 3,988 |   | $ | 4,274 |   |
| Texas Gulf Coast Processing                             |       | 1,910                                                |       | 1,726                                               |       | 5,253 |   | 4,881 |   |
| Mid-Continent Operations(4)                             |       | 2,061                                                |       | —                                              |       | 2,061 |   | — |   |
| Total operations  and maintenance expenses              |       | $                                                    | 5,325      |                                                | $          | 3,186 |   | $ | 11,302 |   | $ | 9,155 |   |

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(1)           Total gross margin is a non-GAAP financial measure. Fora reconciliation of total gross margin to its most directly comparable GAAPmeasure, please read “—Non-GAAP Financial Measures.”

(2)           Excludes results and volumes associated with our interestin Webb/Duval Gatherers. Gross volumes transported by Webb/Duval Gatherers were116,848 MMBtu/d and 118,574 MMBtu/d, net of intercompany volumes, for the 

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three months ended September 30,2005 and 2004, respectively. Gross volumes transported by Webb/Duval Gathererswere 123,645 MMBtu/d and 118,946 MMBtu/d, net of intercompanyvolumes, for the nine months ended September 30, 2005 and 2004,respectively.

(3)           Represents the total processing segment gross margindivided by the total inlet throughput or NGLs produced, as appropriate.

(4)           Represents activities related to theScissorTail Acquisition from August 1, 2005 through September 30,2005. Segment gross margin per unit amounts for the Mid-Continent Operationsare calculated as the segment gross margin divided by the pipeline throughput,inlet throughput or NGLs produced, as appropriate. Plant inlet throughput andNGLs produced represents total volumes processed and produced by theMid-Continent Operations segment at all plants, including plants owned by theMid-Continent Operations segment and plants owned by third parties. Plant inletthroughput averaged 63,059 MMBtu/d and NGLs produced averaged 4,959 for plantsowned by the Mid-Continent Operations segment.

***Three Months Ended September 30, 2005 Compared withThree Months Ended September 30, 2004***

*TexasGulf Coast Pipelines Segment Gross Margin.**  *Texas Gulf Coast Pipelines segmentgross margin was $7.9 million for the three months endedSeptember 30, 2005 compared to $7.4 million for the three monthsended September 30, 2004, an increase of $0.5 million, or 8%. Theincrease was primarily attributable to higher average natural gas prices duringthe three months ended September 30, 2005 compared to the threemonths ended September 30, 2004, which resulted in an increase in marginsassociated with our index price-related gas purchase and transportationarrangements. During the third quarter of 2005, the Houston Ship Channel, orHSC, natural gas index price averaged $8.00 per MMBtu compared to $5.68 perMMBtu during the third quarter of 2004, an increase of $2.32, or 41%.Additionally, a portion of the increase in gross margin for our pipelinesegment resulted from the acquisitions of our Karnes County Gathering System inSeptember 2004 and our Runge Gathering System in December 2004.

*TexasGulf Coast Processing Segment Gross Margin.**  *Texas Gulf Coast Processing segmentgross margin was $7.0 million for the three months endedSeptember 30, 2005 compared to $7.1 million for the three monthsended September 30, 2004, a decrease of $0.1 million, or 1%. For thethree months ended September 30, 2005, we experienced a decrease of$3.1 million in our processing segment gross margin as the result ofhigher natural gas prices, a brief scheduled plant shutdown for maintenance andour election to operate the plant in conditioning mode for a portion of thequarter. For a discussion of the commodity price environment, please read “—HowWe Evaluate Our Operations—Segment Gross Margin.” This decline in ourprocessing segment gross margin during the third quarter of 2005 as compared tothe third quarter of 2004 was offset by increased conditioning fee revenue of$1.7 million and reduced processing upgrade payments of $1.3 millionto natural gas suppliers, including our pipeline affiliates.

*Mid-ContinentOperations Gross Margin.*   On August 1, 2005,Copano completed its acquisition of Tulsa-based ScissorTail, a provider of naturalgas midstream services in Central and Eastern Oklahoma. During the period fromAugust 1, 2005 through September 30, 2005, gross margin for theMid-Continent Operations segment totaled $14.9 million. This segmentgathered or transported an average of 155,153 MMBtu/d of natural gas onits pipelines, processed an average of 102,706 MMBtu/d of natural gas andproduced an average of 8,656 barrels per day of NGLs.

*CorporateSegment Gross Margin.**  *Thecorporate segment gross margin primarily consists of an unrealized loss of$0.3 million for the three months ended September 30, 2005 related toour commodity risk management activities accounted for as fair value hedgesthrough October 24, 2005.

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*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses totaled$5.3 million for the three months ended September 30, 2005 comparedto $3.2 million for the three months ended September 30, 2004. Theincrease of $2.1 million, or 66%, is primarily attributed to ouracquisition of the Mid-Continent Operations on August 1, 2005.

*Depreciationand Amortization.**  *Depreciationand amortization totaled $5.7 million for the three months ended September 30,2005 compared with $2.3 million for the three months ended September 30,2004, an increase of $3.4 million, or 148%. This increase relatesprimarily to additional depreciation and amortization associated withacquisitions and capital expenditures made after September 30, 2004,including the acquisition of our Mid-Continent Operations on August 1,2005, the purchase of compression equipment in 2004, the purchase andmodification of the Karnes County Gathering System during September 2004and the modifications and enhancements made to the Runge Gathering Systemduring the fourth quarter of 2004.

*Generaland Administrative Expenses.**  *General and administrative expenses totaled$4.9 million for the three months ended September 30, 2005 comparedwith $2.4 million for the three months ended September 30, 2004, anincrease of $2.5 million, or 104%. The increase primarily relates to (i) theoperations of our Mid-Continent Operations acquired on August 1, 2005 of$0.8 million and (ii) the costs of being a public company of$1.7 million including (a) costs associated with accounting, legal,director compensation, investor relations, consulting and insurance of$0.4 million, (b) costs related to augmented infrastructure andhiring additional staff of $0.4 million, (c) costs of preparing andprocessing tax K-1s to unitholders of $0.1 million (d) costs ofSarbanes-Oxley readiness of $0.3 million and (e) non-cashcompensation expense related to the amortization of the intrinsic value ofrestricted units issued to employees and directors of $0.5 million.

*Interest Expense.**  *Interest and other financing coststotaled $8.5 million for the three months ended September 30, 2005compared with $3.8 million for the three months ended September 30, 2004. Interestexpense related to our credit facilities totaled $5.1 million and $1.3 millionfor the three months ended September 30, 2005 and 2004, respectively. Averageborrowings under these credit facilities were $227.5 million and$71.0 million with average interest rates of 7.1% and 6.9% for the thirdquarter 2005 and 2004, respectively. Amortization of debt issue costs totaled$3.4 million and $0.2 million for the three months ended September 30,2005 and 2004, respectively. Amortization of debt issue cost for the threemonths ended September 30, 2005 included a one-time charge of $1.6 millionrelated to the early termination of the CPG Credit Agreement and the CHCFacility discussed in Note 5 to the unaudited consolidated financial statements.Additionally, interest expense for the three months ended September 30,2004 included $2.3 million of interest related to the payment-in-kindpreferred units issued to certain Pre-Offering Investors that held theredeemable preferred units, the accretion of the allocated warrant valueassociated with the redeemable preferred units and payment-in-kind interestunder a term loan entered into in 2001. The increase in interest expense is dueprimarily to borrowings under our Credit Facility and Term Loan Facility,discussed in “—Liquidity and Capital Resources—Our Indebtedness,” as a resultof our acquisition of ScissorTail on August 1, 2005.

***Nine Months Ended September 30, 2005 Comparedwith Nine Months Ended September 30, 2004***

*TexasGulf Coast Pipelines Segment Gross Margin.**  *Texas Gulf Coast Pipelines segmentgross margin was $23.3 million for the nine months ended September 30,2005 compared to $21.4 million for the nine months ended September 30,2004, an increase of $1.9 million, or 9%. The increase was primarilyattributable to higher average natural gas prices during the nine months ended September 30, 2005compared to the nine months ended September 30, 2004, which resulted in anincrease in margins associated with our index price-related gas purchaseand transportation arrangements. During the nine months ended September 30,2005, the HSC natural gas index price averaged $6.80 per MMBtu compared to$5.62 per MMBtu during the nine months ended September 30, 2004, anincrease of $1.18, or 21%. 

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Additionally, a portion ofthe increase in gross margin for our pipeline segment resulted from theacquisitions of our Karnes County Gathering System in September 2004 andour Runge Gathering System in December 2004.

*TexasGulf Coast Processing Segment Gross Margin.**  *Texas Gulf Coast Processing segmentgross margin was $20.5 million for the nine months ended September 30,2005 compared to $12.6 million for the nine months ended September 30,2004, an increase of $7.9 million, or 63%. For the nine months ended September 30,2005, we experienced improvements of $9.0 million in our processingsegment gross margin as the result of increased plant utilization and animproved commodity price environment. For a discussion of the commodity priceenvironment, please read “—How We Evaluate Our Operations—Segment Gross Margin.”Our processing segment gross margin was further improved during the nine monthsended September 30, 2005 as compared to the nine months ended September 30,2004 as a result of increased conditioning fee revenue of $0.3 million. Thisincreased processing segment gross margin was partially offset by an increasein processing upgrade payments of $1.4 million to natural gas suppliers,including our pipeline affiliates, during the nine months ended September 30,2005 as compared to the nine months ended September 30, 2004.

*Mid-ContinentOperations Gross Margin.**  *On August 1, 2005, Copano completed itsacquisition of Tulsa-based ScissorTail and during the period from August 1,2005 through September 30, 2005, gross margin for the Mid-ContinentOperations segment totaled $14.9 million. This segment gathered ortransported an average of 155,153 MMBtu/d of natural gas on its pipelines,processed an average of 102,706 MMBtu/d of natural gas and produced anaverage of 8,656 barrels per day of NGLs.

*CorporateSegment Gross Margin.**  *Thecorporate segment gross margin primarily consists of an unrealized loss of$0.3 million for the nine months ended September 30, 2005 related toour commodity risk management activities accounted for as fair value hedgesthrough October 24, 2005.

*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses totaled$11.3 million for the nine months ended September 30, 2005 comparedto $9.2 million for the nine months ended September 30, 2004. Theincrease of $2.1 million, or 23%, is primarily attributed to ouracquisition of the Mid-Continent Operations on August 1, 2005.

*Depreciationand Amortization.**  *Depreciationand amortization totaled $9.4 million for the nine months ended September 30,2005 compared with $5.5 million for the nine months ended September 30,2004, an increase of $3.9 million, or 71%. This increase relates primarilyto additional depreciation and amortization associated with acquisitions andcapital expenditures made after September 30, 2004, including theacquisition of our Mid-Continent Operations on August 1, 2005, thepurchase of compression equipment in 2004, the purchase and modification of theKarnes County Gathering System during September 2004 and the modificationsand enhancements made to the Runge Gathering System during the fourth quarterof 2004.

*Generaland Administrative Expenses.**  *General and administrative expenses totaled$11.4 million for the nine months ended September 30, 2005 comparedwith $5.9 million for the nine months ended September 30, 2004, anincrease of $5.5 million, or 93%. The increase primarily relates to (i) theoperations of our Mid-Continent Operations acquired on August 1, 2005 of$0.8 million and (ii) the costs of being a public company of$4.6 million including (a) costs associated with accounting, legal,director compensation, investor relations, consulting and insurance of$1.1 million, (b) costs related to augmented infrastructure andhiring additional staff of $1.7 million, (c) costs of preparing andprocessing tax K-1s to unitholders of $0.5 million, (d) costsassociated with Sarbanes-Oxley readiness of $0.6 million and (e) non-cashcompensation expense related to the amortization of the intrinsic value ofrestricted units issued to employees and directors of $0.7 million. Additionally,we incurred $0.1 million related to growth and acquisition initiativesduring the nine months ended September 30, 2005.

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*Interest Expense.**  *Interest and other financing coststotaled $10.5 million for the nine months ended September 30, 2005compared with $11.5 million for the nine months ended September 30, 2004. Interestexpense related to our credit facilities totaled $6.8 million and $3.8 millionfor the nine months ended September 30, 2005 and 2004, respectively. Averageborrowings under these credit facilities were $229.5 million and$68.4 million with average interest rates of 7.1% and 6.9% for 2005 periodand 2004 period, respectively. Amortization of debt issue costs totaled$3.7 million and $0.9 million for the nine months ended September 30,2005 and 2004, respectively. Amortization of debt issue costs for the ninemonths ended September 30, 2005 included one-time charges of $1.6 millionrelated to the early termination of the CPG Credit Agreement and the CHCFacility discussed in Note 5 to the unaudited consolidated financial statements.Amortization of debt issue cost for the nine months ended September 30,2004 included a one-time charge of $0.3 million related to the earlytermination of the then outstanding Texas Gulf Coast Processing credit facility.Additionally, interest expense for the nine months ended September 30,2004 included $6.8 million of interest related to the payment-in-kindpreferred units issued to certain Pre-Offering Investors that held theredeemable preferred units, the accretion of the allocated warrant valueassociated with the redeemable preferred units and payment-in-kind interestunder a term loan entered into in 2001. The decrease in interest expense is dueprimarily to our redemption of the redeemable preferred units offset byborrowings under our Credit Facility and Term Loan Facility, discussed in “—Liquidityand Capital Resources—Our Indebtedness,” as a result of our acquisition ofScissorTail on August 1, 2005.

***Impact of Inflation***

Inflation in the UnitedStates has been relatively low in recent years and did not have a materialimpact on our results of operations for the periods presented. Although theimpact of inflation has not been significant in recent years, it is still afactor in the United States economy and may increase the cost to acquire orreplace property, plant and equipment and may increase the cost of labor andsupplies, and capital available to us. To the extent permitted by competition,regulation and our existing agreements, we may pass along increased costs toour customers in the form of higher fees.

***Liquidity and Capital Resources***

Cash generated from operations, borrowings under ourcredit facilities and funds from equity and debt offerings are our primarysources of liquidity. We believe that funds from these sources should besufficient to meet both our short-term working capital requirements and ourlong-term capital expenditure requirements. Our ability to pay distributions toour unitholders, to fund planned capital expenditures and to make acquisitionswill depend upon our future operating performance, and more broadly, on theavailability of equity and debt financing, which will be affected by prevailingeconomic conditions in our industry and financial, business and other factors,some of which are beyond our control.

*Off-BalanceSheet Arrangements.**  *Wehad no off-balance sheet arrangements as of September 30, 2005.

*Capital Requirements.**  *The natural gas gathering,transmission, and processing businesses are capital-intensive, requiringsignificant investment to maintain and upgrade existing operations. Our capitalrequirements have consisted primarily of, and we anticipate will continue tobe:

·       maintenancecapital expenditures, which are capital expenditures made to replace partiallyor fully depreciated assets to maintain the existing operating capacity of ourassets and to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows; and

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·       expansioncapital expenditures such as those to acquire additional assets to grow our business,to expand and upgrade gathering systems, transmission capacity, processingplants, and to construct or acquire new pipelines or processing plants.

Given our objective of growth through acquisitions, weanticipate that we will continue to invest significant amounts of capital togrow and acquire assets. We actively consider a variety of assets for potentialacquisitions. For a discussion of the primary factors we consider in decidingwhether to pursue a particular acquisition, please read “—Our Growth Strategy—AcquisitionAnalysis.”

During the nine months ended September 30, 2005,our total capital expenditures incurred of $487.7 million consisted of$2.8 million of maintenance capital and $484.9 million of expansioncapital, including the ScissorTail Acquisition. We funded our capitalexpenditures with funds from operations, borrowings under our credit facilitiesand the issuance of additional equity. Additional expansion capitalexpenditures related to completing the integration of the Runge GatheringSystem, purchasing compressors and constructing well interconnections to attachvolumes in new areas. We expect to fund future capital expenditures with fundsgenerated from our operations, borrowings under our credit facilities and the issuanceof additional equity or debt as appropriate given market conditions. Weanticipate expending approximately $7.0 million of maintenance capitalover the next 12 months.

*Total Contractual CashObligations.**  *Asummary of our total contractual cash obligations as of September 30, 2005is as follows:

| ** **                          | ** ** | ** **              | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------|------------|-------------------------|------------|------------------------------------------|------------|
| **Type of Obligation**    | ** ** | ** **              | ** ** | **Total  Obligation**                    | ** ** | **Remainder  of 2005** | ** ** | **2006/2007** | ** ** | **2008/2009** | ** ** | **Thereafter** | ** ** |
| ** **                          | ** ** | **(in thousands)** | ** ** |
| Debt                                |       | $                       | 402,000    |                                     |       | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 402,000 |   |
| Interest                            |       | 146,898                 |       |                                     | 7,800      |   |   |   | 58,702 |   |   |   | 57,639 |   |   | 22,757 |   |
| Operating Leases                    |       | 2,977                   |       |                                     | 426        |   |   |   | 1,484 |   |   |   | 723 |   |   | 344 |   |
| Total contractual  cash obligations |       | $                       | 551,875    |                                     |       | $ | 8,226 |   |   |   | $ | 60,186 |   |   |   | $ | 58,362 |   |   | $ | 425,101 |   |
|                                     |            |                         |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

In addition to the contractual obligations noted inthe table above, we have both fixed and variable quantity contracts to purchasenatural gas, which were executed in connection with our natural gas marketingactivities. As of September 30, 2005, we had fixed contractual commitmentsto purchase 6,118,625 MMBtu of natural gas in October 2005. All ofthese contracts were based on index-related prices. Using these index-relatedprices at September 30, 2005, we had total commitments to purchase$52.0 million of natural gas under such agreements. Our contracts topurchase variable quantities of natural gas at index-related prices rangefrom one month to the life of the dedicated production. During September 2005,we purchased 8,679,621 MMBtu of natural gas under such contracts.

*Cash Flows.**  *The following summarizes our cashflows for the nine months ended September 30, 2005 and 2004.

| ** **                                           | ** ** | **Nine Months  Ended September 30,** | ** ** |
|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                           | ** ** | **2005**                                            | ** ** | **2004** | ** ** |
| ** **                                           | ** ** | **(in thousands)**                             | ** ** |
| Net cash provided  by operating activities           |       | $                                                   | 12,071     |   | $ | 7,706 |   |
| Net cash used in  investing activities               |       | (486,458                                            | )          | (5,523 | ) |
| Net cash provided  by (used in) financing activities |       | 497,185                                             |       | (709 | ) |
| Net increase in  cash and cash equivalents           |       | 22,798                                              |       | 1,474 |   |
| Cash and cash  equivalents at beginning of year      |       | 7,015                                               |       | 4,607 |   |
| Cash and cash  equivalents at end of period          |       | $                                                   | 29,813     |   | $ | 6,081 |   |

 

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*Operating:*

| ** **                                                            | ** ** | **Nine Months  Ended September 30,** | ** ** |
|-----------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                            | ** ** | **2005**                                            | ** ** | **2004** | ** ** |
| Net income                                                            |       | $                                                   | 16,100     |   | $ | 1,491 |   |
| Depreciation and  amortization                                        |       | 13,086                                              |       | 6,410 |   |
| Equity in  earnings from unconsolidated affiliate                     |       | (726                                                | )          | (263 | ) |
| Deferred stock  compensation and other                                |       | 636                                                 |       | (5 | ) |
| Non-cash interest  expense                                            |       | —                                              |       | 7,579 |   |
| Cash used in  working capital, net of acquired assets and liabilities |       | (17,025                                             | )          | (7,506 | ) |
| Net cash provided by  operating activities                            |       | $                                                   | 12,071     |   | $ | 7,706 |   |

 

The overall increase of $4.4 million in operatingcash flow for the nine months ended September 30, 2005 compared to thenine months ended September 30, 2004 was primarily the result of anincrease in net income of $14.6 million, a decrease in non-cash items of$0.7 million and an decrease in the changes in working capital components(exclusive of cash and cash equivalents) of $9.5 million. This decrease inthe changes in working capital components (exclusive of cash and cashequivalents) was primarily the result of a increase in accounts receivable of$20.5 million offset by a increase in accounts payable of$11.0 million.

We believe that we will continue to have adequateliquidity to fund future recurring operating and investing activities. Ourprimary cash requirements consist of normal operating expenses, capitalexpenditures to sustain existing operations and revenue generatingexpenditures, interest payments on our credit facilities, distributions to ourunitholders and acquisitions of new assets or businesses. Short-term cashrequirements, such as operating expenses, capital expenditures to sustainexisting operations and quarterly distributions to our unitholders, areexpected to be funded through operating cash flows. Long-term cash requirementsfor expansion projects and acquisitions are expected to be funded by severalsources, including cash flows from operating activities, borrowings under ourcredit facilities, and the issuance of additional equity and debt securities,as appropriate. Our ability to complete future debt and equity offerings andthe timing of any such offerings will depend on various factors, includingprevailing market conditions, interest rates, our financial condition and ourcredit rating at the time.

*Investing:*   Netcash used in investing activities was $486.5 million for the nine monthsended September 30, 2005 compared to $5.5 million for the nine monthsended September 30, 2004. Capital expenditures for 2005 include costsrelated to our ScissorTail Acquisition on August 1, 2005 and several smallpipeline systems, completing the integration of the Runge Gathering System,building well interconnections, purchasing compressors, constructing amonitoring and control system for our NGL line and upgrading dehydrationfacilities at the inlet to the cryogenic portion of our Houston CentralProcessing Plant slightly offset by the release of restricted cash. Capitalexpenditures in 2004 include expenditures for the acquisition of compressionequipment and the development and installation of our SCADA system offset bythe release of restricted cash.

*Financing:*   Netcash provided by financing activities totaled $497.2 million during thenine months ended September 30, 2005 and included (i) net borrowingsunder our credit facilities of $345.0 million, (ii) net proceeds fromthe private placement of common units and Class B units of$174.0 million and (iii) capital contributions of $2.6 million fromour Pre-Offering Investors offset by (a) distributions to our unitholdersof $14.9 million and (b) deferred financing costs of $9.5 million.Net cash used by financing activities of $0.7 million during the ninemonths ended September 30, 2004 was primarily attributable to our netborrowings of $3.5 million in long-term debt offset by deferred financingcosts of $1.6 million and deferring Offering costs of $2.6 million.

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*CashDistributions and Reserves:*   Within 45 daysafter the end of each quarter, we intend to pay quarterly in arrears (inFebruary, May, August and November of each year), to the extent wehave sufficient available cash from operating surplus as defined in our limitedliability company agreement, no less than the minimum quarterly distribution,or MQD, of $0.40 per unit (or $1.60 per year), to our common and subordinatedunitholders of record on the applicable record date. During the subordinationperiod, the common units will have the right to receive distributions ofavailable cash from operating surplus in an amount equal to the MQD of $0.40per quarter, plus any arrearages in the payment of the MQD on the common unitsfrom prior quarters, before any distributions of available cash from operatingsurplus may be made on the subordinated units.

Our available cash consists generally of all cash onhand at the end of the fiscal quarter, less retained cash reserves that ourboard determines are necessary to a) provide for the proper conduct of ourbusiness; b) comply with applicable law, any of our debt instruments, or otheragreements; or (c) provide funds for distributions to our unitholders forany one or more of the next four quarters; plus all cash on hand for thequarter resulting from eligible working capital borrowings made after the endof the quarter on the date of determination of available cash. Operating surplus generally consists of cashon hand at closing, cash generated from operations after deducting relatedexpenditures and other items, plus eligible working capital borrowings after the end of the quarter, plus $12.0million, as adjusted for reserves. We have not established a creditfacility that provides for the type of working capital borrowings that would beeligible, pursuant to our limited liability company agreement, to be consideredavailable cash or operating surplus distributable to our unitholders.

Our board has broad discretion to establish cashreserves that it determines are necessary or appropriate to properly conductour business. These can include cash reserves for future capital andmaintenance expenditures, reserves to stabilize distributions of cash to theunitholders, reserves to reduce debt or, as necessary, reserves to comply withthe terms of any of our agreements or obligations.

On February 14, 2005, we paid cash distributionsof $2.1 million, or $0.20 per unit, which reflected a pro rata portion ofour MQD for the period from November 15, 2004 (the closing of theOffering) through December 31, 2004. On May 13, 2005, we paid $4.5 millionof cash distributions representing $0.42 per unit, or $1.68 per unitannualized, for the three months ended March 31, 2005. On July 15, 2005,our board declared a cash distribution for the three months ended June 30,2005 of $0.45 per unit, or $1.80 per unit annualized, for alloutstanding common and subordinated units. The distribution totaling$7.8 million was paid on August 15, 2005 to holders of record at theclose of business on August 1, 2005 and included 1,372,458 common unitsissued in connection with the closing of the ScissorTail Acquisition. Thisdistribution amount also included a concurrent quarterly distribution of $.0495per unit with respect to 4,830,758 Class B units issued in connection withthe closing of the ScissorTail Acquisition. The Class B unit distributionrepresented a quarterly distribution equal to 110% of the per unit distributionreceived by the common units. On October 27, 2005, our unitholders approvedthe conversion of each of the Class B units into one common unit and theissuance of 4,830,758 additional common units upon such conversion.

On October 17, 2005, our board declared acash distribution for the three months ended September 30, 2005 of $0.50 perunit, or $2.00 per unit annualized, for all outstanding common andsubordinated units. The distribution totaling $8.4 million will be paid onNovember 14, 2005 to holders of record at the close of business on November 1,2005.

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Theamount of available cash from operating surplus needed to pay the currentdistribution of $0.50 per unit, or $2.00 per unit annualized, to ourcommon and subordinated unitholders is as follows (in thousands):

| ** **          | ** ** | **One Quarter** | ** ** | **Four Quarters** | ** ** |
|---------------------|------------|----------------------|------------|------------------------|------------|
| Common units(1)     |       |                 | $          | 6,689                  |       |   |   | $ | 26,758 |   |   |
| Subordinated  units |       |                 | 1,760      |                   |       |   | 7,038 |   |   |
| Total               |       |                 | $          | 8,449                  |       |   |   | $ | 33,796 |   |   |

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(1)          Includesrestricted common units issued under our long-term incentive plan.Distributions made on restricted units issued to date are subject to the samevesting provisions as the restricted units. As of November 1, 2005, we had135,070 outstanding restricted units, of which 262 units have vested. Annualdistributions related to these restricted units are approximately $270,000.

***Our Indebtedness***

*New$350 Million Credit Facility.**  *OnAugust 1, 2005, we entered into a new $350 million senior securedrevolving credit facility (the “Credit Facility”) with Bank of America, N.A.,as Administrative Agent, Banc of America Securities LLC, as Sole Lead Arrangerand Sole Book Manager and a group of financial institutions, as lenders. TheCredit Facility includes a $25 million sublimit for the issuance ofstandby letters of credit and matures on July 31, 2010.

On August 1, 2005, we borrowed $232.0 millionunder the Credit Facility to: (i) partially finance the ScissorTail Acquisitionand (ii) to repay in full indebtedness outstanding under the CPG CreditAgreement and the CHC Facility. Additionally, in connection with ourScissorTail Acquisition, a $0.9 million standby letter of credit wasassumed by us, which remains outstanding at September 30, 2005. Futureborrowings under the Credit Facility are available for acquisitions, capitalexpenditures, working capital and general corporate purposes. The CreditFacility does not provide for the type of working capital borrowings that wouldbe eligible, pursuant to our limited liability company agreement, to beconsidered available cash distributable to our unitholders. The Credit Facilityis available to be drawn on and repaid without restriction so long as we are incompliance with the terms of the Credit Facility, including certain financialcovenants.

The Credit Facility contains various covenants thatlimit our and certain of our operating subsidiaries’ ability to grant certainliens; make certain loans and investments; make certain capital expendituresoutside our current lines of business or certain related lines of business;make distributions other than from available cash (as defined in our limitliability company agreement); merge or consolidate with or into a third party;or engage in certain asset dispositions, including a sale of all orsubstantially all of our assets. Additionally, the Credit Facility limits ourand certain of our operating subsidiaries’ ability to incur additionalindebtedness with certain exceptions, including under the Term Loan Facility(as discussed below), purchase money indebtedness and indebtedness related tocapital or synthetic leases not to exceed $5.0 million, unsecured indebtednessnot to exceed $5.0 million and unsecured indebtedness qualifying assubordinated debt. 

The Credit Facilityalso contains covenants, which, among other things, require us and certain ofour subsidiaries, on a consolidated basis, to maintain specified ratios or conditionsas follows:

·       EBITDA(as defined) to interest expense of not less than 2.5 to 1.0 through September 30,2005, 2.75 to 1.0 from December 31, 2005 through June 30, 2006 and3.0 to 1.0 thereafter;

·       EBITDAminus maintenance capital expenditures to consolidated fixed charges of notless than 1.5 to 1.0 through September 30, 2005 and 1.75 to 1.0thereafter;

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·       totaldebt to EBITDA of not more than 5.5 to 1.0 through September 30, 2005, 5.0to 1.0 from December 31, 2005 through June 30, 2006 and 4.75 to 1.0thereafter; and

·       totalsenior debt to EBITDA of not more than 3.75 to 1.0 through September 30,2005 and 3.5 to 1.0 thereafter.

Based upon the senior debt to EBITDA ratio calculatedas of September 30, 2005 (utilizing trailing four quarters’ EBITDA asdefined under the Credit Facility), we have approximately $118.0 millionof unused capacity under the Credit Facility.

The obligations under the Credit Facility are securedby first priority liens on substantially all of our assets and substantiallyall of the assets of our subsidiaries (other than WDG, Southern Dome andcertain subsidiaries with insignificant assets). Additionally, the obligationsunder the Credit Facility are guaranteed by substantially all of oursubsidiaries (other than WDG, Southern Dome and certain subsidiaries withinsignificant assets).

At our election, interest under the Credit Facility isdetermined by reference to (i) the British Bankers Association LIBOR rate,or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum or (ii) thehigher of the federal funds rate plus 0.5% or the prime rate plus, in eithercase, an applicable margin between 0.25% and 1.25% per annum. Interest ispayable quarterly for prime rate loans and at the applicable maturity date forLIBOR loans, except that if the interest period for a LIBOR loan is ninemonths, interest will be paid at the end of each three-month period.

If an event ofdefault occurs under the Credit Facility, the lenders would be able toaccelerate the maturity of the obligations outstanding under the CreditFacility and exercise other rights and remedies. Each of the following would bean event of default:

·       failureto pay any principal when due or any interest, fees or other amount withincertain grace periods;

·       failureto perform or otherwise comply with the covenants in the credit agreement orother loan documents, subject, in certain instances, to certain grace periods;

·       defaultby us on the payment of any other indebtedness in excess of $5.0 million, or anydefault in the performance of any obligation or condition with respect to suchindebtedness beyond the applicable grace period if the effect of the default isto permit or cause the acceleration of the indebtedness;

·       bankruptcyor insolvency events involving us or our subsidiaries;

·       theentry of, and failure to pay, one or more adverse judgments in excess of $5.0million against which enforcement proceedings are brought or that are notstayed pending appeal; and

·       achange of control (as defined in the Credit Facility).

The effective average interest rate on borrowingsunder the Credit Facility was 5.95% and the quarterly commitment fee on theunused portion of the Credit Facility was 0.3% as of September 30, 2005. Interestand other financing costs related to the Credit Facility totaled$2.5 million for the period from August 1, 2005 through September 30,2005. Costs incurred in connection with the establishment of this creditfacility are being amortized over the term of the Credit Facility, and as of September 30,2005, the unamortized portion of debt issue costs totaled $4.9 million.

Management believes that we are in compliance with thecovenants under the Credit Facility as of September 30, 2005. If an eventof default exists under the Credit Facility, the lenders will be able toaccelerate the maturity of the credit agreement and exercise other rights andremedies.

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*TermLoan Facility.**  *On August 1, 2005, we enteredinto a $170 million senior unsecured term loan facility (the “Term LoanFacility”) with Banc of America Bridge LLC, as the Lender and Banc of AmericaSecurities LLC, as Sole Lead Arranger and Sole Book Manager. The proceeds fromthe Term Loan Facility were used to pay a portion of the purchase price of the ScissorTailAcquisition.

The Term Loan Facility matures on August 1, 2006.Any outstanding term loans on August 1, 2006 (the “Conversion Date”) willbe automatically converted into new term loans with a six year term (the “RolloverLoans”) subject to satisfaction of certain conditions. On and after theConversion Date, the Lenders (as defined in the Term Loan Facility) holding atleast $42.5 million of the Rollover Loans may elect to exchange their RolloverLoans for exchange notes, which will be governed by the Exchange Note Indenture(as defined in the Term Loan Facility). The obligations under the Term LoanFacility are general unsecured obligations of our company and certain of itssubsidiaries and are guaranteed by substantially all of our subsidiaries (otherthan WDG, Southern Dome and certain subsidiaries with insignificant assets).

The Term Loan Facility contains customary restrictivecovenants pertaining to management and operations of our company and oursubsidiaries, which are substantially similar to those contained in the CreditFacility. The Term Loan Facility also includes the same financial covenants asthose contained in the Credit Facility except that the required interestexpense and consolidated fixed charge coverage ratios have been set at 0.5 to1.0 lower and the permitted total debt and total senior debt to EBITDA ratioshave been set 0.5 to 1.0 higher. Generally, amounts outstanding under the TermLoan Facility will bear interest at a base rate being the greater of (i) three-monthLIBOR plus an applicable margin initially equal to 5% per annum or (ii) 8.5%per year; provided that the rates and margins increase by 0.5% per quarterwhile the Term Loan Facility remains outstanding subject to a cap of 11%(subject to certain additional interest rate increases in certaincircumstances). In addition, the Term Loan Facility contains covenants thatobligate us to use commercially reasonable efforts to refinance the Term LoanFacility as promptly as practicable and, within certain time periods, toprepare the Exchange Note Indenture and to register the related exchange noteswith the Securities and Exchange Commission.

The Term Loan Facility also includes events of defaultsubstantially similar to those contained in the Credit Facility. If an event ofdefault under the Term Loan Facility shall occur and be continuing, theprincipal amount outstanding thereunder, together with all accrued unpaidinterest and other amounts owed thereunder, may be declared immediately due andpayable.

The effective average interest rate on borrowingsunder the Term Loan Facility was 8.69% as of September 30, 2005. Interestand other financing costs related to the Term Loan Facility totaled$4.1 million for the period from August 1, 2005 through September 30,2005. Costs incurred in connection with the establishment of this creditfacility are being amortized over the estimated term of the Term Loan Facility,and as of September 30, 2005, the unamortized portion of debt issue coststotaled $2.3 million.

Management believes thatwe are in compliance with the covenants under the Term Loan Facility as of September 30,2005. If an event of default exists under the Term Loan Facility, the lenderswill be able to accelerate the maturity of the credit agreement and exerciseother rights and remedies.

***Recent Accounting Pronouncements***

For information on newaccounting pronouncements, please read Note 2 to the unaudited consolidatedfinancial statements.

***Critical Accounting Policies***

For a discussion of ourcritical accounting policies, which are related to revenue recognition,depreciation, amortization and impairment of long-lived assets and financialinstruments previously 

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classifiedas equity and are now classified as liabilities and equity method ofaccounting, and which remain unchanged, please read “Management’s Discussionand Analysis of Financial Condition and Results of Operation—SignificantAccounting Policies and Estimates” in our Annual report on Form 10-K forthe year ended December 31, 2004.

***Non-GAAP Financial Measures***

Thefollowing table presents a reconciliation of the non-GAAP financial measures of(i) total gross margin (which consists of the sum of individual segmentgross margins) to the GAAP financial measure of operating income and (ii) EBITDAto the GAAP financial measures of net income and cash flows from operatingactivities for each of the periods indicated (in thousands).

| ** **                                                         | ** ** | **Three Months  Ended September 30,** | ** ** | **Nine Months  Ended September 30,** | ** ** |
|--------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                         | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Reconciliation of total  gross margin to operating income:         |       |                                                 |       |                                                |       |   |   |   |   |
| Operating income                                                   |       | $                                                    | 13,533     |                                                | $          | 6,483 |   | $ | 26,313 |   | $ | 12,983 |   |
| Add: Operations and maintenance expenses                           |       | 5,325                                                |       | 3,186                                               |       | 11,302 |   | 9,155 |   |
| Depreciation and amortization                                      |       | 5,706                                                |       | 2,252                                               |       | 9,371 |   | 5,498 |   |
| General and administrative expenses                                |       | 4,878                                                |       | 2,387                                               |       | 11,408 |   | 5,884 |   |
| Taxes other than income                                            |       | 321                                                  |       | 247                                                 |       | 713 |   | 748 |   |
| Equity in earnings from unconsolidated affiliates                  |       | (240                                                 | )          | (96                                                 | )          | (726 | ) | (263 | ) |
| Total gross margin                                                 |       | $                                                    | 29,523     |                                                | $          | 14,459 |   | $ | 58,381 |   | $ | 34,005 |   |
| Reconciliation of EBITDA  to net income:                           |       |                                                 |       |                                                |       |   |   |   |   |
| Net income                                                         |       | $                                                    | 5,159      |                                                | $          | 2,703 |   | $ | 16,100 |   | $ | 1,491 |   |
| Add: Depreciation and amortization                                 |       | 5,706                                                |       | 2,252                                               |       | 9,371 |   | 5,498 |   |
| Interest expense and other financing costs                         |       | 8,542                                                |       | 3,805                                               |       | 10,532 |   | 11,539 |   |
| EBITDA                                                             |       | $                                                    | 19,407     |                                                | $          | 8,760 |   | $ | 36,003 |   | $ | 18,528 |   |
| Reconciliation of EBITDA  to cash flows from operating activities: |       |                                                 |       |                                                |       |   |   |   |   |
| Cash flow (used in) provided by operating activities               |       | $                                                    | (3,922     | )                                                   | $          | 4,181 |   | $ | 12,071 |   | $ | 7,706 |   |
| Add: Cash paid for interest and other financing  costs             |       | 5,156                                                |       | 1,302                                               |       | 6,817 |   | 3,048 |   |
| Equity in earnings of unconsolidated affiliates                    |       | 240                                                  |       | 96                                                  |       | 726 |   | 263 |   |
| Increase in working capital and other                              |       | 17,933                                               |       | 3,181                                               |       | 16,389 |   | 7,511 |   |
| EBITDA                                                             |       | $                                                    | 19,407     |                                                | $          | 8,760 |   | $ | 36,003 |   | $ | 18,528 |   |

 

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**Item3.**                        Quantitativeand Qualitative Disclosures About Market Risk.

Market risk is the risk ofloss arising from adverse changes in market rates and prices. We are exposed tomarket risks, including changes in commodity prices and interest rates. We mayuse financial instruments such as puts, swaps, options and other financialinstruments with similar characteristics to mitigate the risks of certainidentifiable and anticipated transactions consistent with our Risk ManagementPolicy. In general, the type of risks we attempt to hedge are those related tothe variability of future earnings, fair values of certain debt instruments andcash flows resulting from changes in applicable commodity prices or interestrates. As a matter of policy, we do not use financial instruments forspeculative (or “trading”) purposes.

*Interest Rate Risk.**  *Our interest rate exposure resultsfrom variable rate borrowings under our debt agreements. During the quarterended September 30, 2005, we were exposed to changes in interest rates asa result of the indebtedness outstanding under our credit facilities of$402.0 million, which had an average floating interest rate of 7.1% as of September 30,2005. The impact of a 1% increase in interest rates on this amount of debtwould result in an increase in interest expense and a corresponding decrease innet income of approximately $4.0 million annually.

We manage a portion of ourinterest rate exposure by utilizing interest rate swaps, which allow us toconvert a portion of variable rate debt into fixed rate debt. In October 2005,we entered into two interest rate swap agreements with an aggregate notionalamount of $50 million in which we exchanged the payment of variable rateinterest on a portion of the principal outstanding under the Credit Facilityfor fixed rate interest. We have designated these two interest rate swaps ascash flow hedges under SFAS No. 133, “*Accounting for Derivative Instruments and Hedging Activities*”(as amended and interpreted). Under each swap agreement, we will pay thecounterparties the fixed interest rate of approximately 4.7% monthly and willreceive back from the counterparties a variable interest rate based onone-month LIBOR rates. The interest rate swaps cover the period from October 2005through July 2010 and the settlement amounts will be recognized toearnings as either an increase or a decrease in interest expense.

*Commodity Price Risks.**  *Our profitability is affected byprevailing NGL and natural gas prices. NGL and natural gas prices are volatileand are impacted by changes in the supply and demand for NGLs and natural gas,as well as market uncertainty and a variety of additional factors that arebeyond our control. Natural gas prices can also affect our profitabilityindirectly by influencing the level of drilling activity and relatedopportunities for our services. We believe our sensitivity to crude oil,natural gas and NGL prices has been reduced as a result of the ScissorTailAcquisition and our risk management activities.

In order to calculate thesensitivity of our gross margin to commodity price changes, we adjusted ouroperating models for actual commodity prices, plant recovery rates and volumes.Our analysis included the operations of our newly acquired Mid-ContinentOperations segment, beginning on August 1, 2005. We have calculated that a1-cent per gallon change in either direction of NGL prices would haveresulted in a corresponding change of approximately $1.4 million to ourgross margin for the nine months ended September 30, 2005. We alsocalculated that a 10-cent per MMBtu increase in the price of natural gaswould have resulted in approximately a $1.2 million decrease to our grossmargin, and vice versa, for the nine months ended September 30, 2005.

These relationships arenot entirely linear. If processing margins are negative, we can operate ourHouston Central Plant in a conditioning mode so that additional increases innatural gas prices would have a positive impact to our gross margin.

In addition, throughoutthe third quarter of 2005, we received conditioning fees and related benefitsin the form of suspended processing payments (the “Conditioning Benefits”)resulting in aggregate benefits of $1.7 million under our processing agreementwith Kinder Morgan Texas Pipeline, L.P., or KMTP, at the Houston Central Plant.Under the terms of the KMTP processing agreement, we did not receive ConditioningBenefits during the first six months of 2005. Had higher NGL prices or lowernatural 

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gasprices been in effect immediately prior to the beginning of a month, we may nothave received the Conditioning Benefits. However, the reduced benefits wouldhave been partially or fully offset by increased margins derived fromprocessing KMTP’s gas. The sensitivity analysis provided above for the ninemonths ended September 30, 2005 does not reflect the impact of the ConditioningBenefits we received in the third quarter.

Weengage in risk management activities that generally take the form of commodityderivative instruments. These activities are governed by our Risk ManagementPolicy, which prohibits speculative transactions and limits the type, maturityand notional amounts of derivative transactions. The policy allows managementto purchase crude oil and natural gas liquids puts and certain natural gas putor call options in order to reduce our exposure to a substantial adverse changein the prices of those commodities. Our Risk Management Committee monitors andensures compliance with our risk management policy and is comprised of seniorlevel executives in the operations, finance and legal departments. The AuditCommittee of our Board of Directors monitors the implementation of the policyand we have engaged an independent firm to provide additional oversight. Ourrisk management policy requires derivative transactions to take place either onthe New York Mercantile Exchange (NYMEX) through a clearing member firm or withover the counter counterparties with investment grade ratings from both Moody’sand Standard & Poor’s. Potential derivative transactions are analyzedto evaluate their efficacy within our risk management strategy.

In late July 2005, weentered into put transactions for the sale of West Texas Intermediate crude oilwith a combined notional amount of 60,000 barrels per month for a term from September 2005through December 2007. The counterparties have investment grade ratings. Thederivatives are intended to hedge the risk of weakening NGL prices withoffsetting increases in the value of the puts based on the correlation betweenNGL prices and crude oil prices. We designated these two transactions as cashflow hedges under SFAS No. 133 effective October 25, 2005. For theperiod ended September 30, 2005, the Company recorded a fair value lossagainst other revenue of $0.3 million related to these put contracts. Asof September 30, 2005, the fair value of these contracts totaled$3.6 million. Since these puts give us the right to sell crude oil atspecified prices, the market value of the derivatives is inversely related tothe market price of West Texas Intermediate crude oil. At September 30,2005, holding all other factors constant, an upward shift in the forward curveof $0.01 per gallon, or $0.42 per barrel, would have reduced the market valueof the puts by approximately $0.1 million. Conversely, a downward shift inthe forward curve of $0.01 per gallon would have increased the market valueof the puts by approximately $0.1 million, assuming all other factors areheld constant.

*Credit Risk.**  *We are diligent in attempting to ensure that weprovide credit to only credit-worthy customers. However, our purchase andresale of natural gas exposes us to significant credit risk, as the margin onany 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.

**Item4.**                        Controlsand Procedures.

We carried out anevaluation under the supervision and with the participation of our management,including our Chief Executive Officer and Chief Financial Officer, of theeffectiveness of our disclosure controls and procedures as of the end of theperiod covered by this report. Based on the valuation, the Chief ExecutiveOfficer and Chief Financial Officer concluded that our disclosure controls andprocedures were effective to provide reasonable assurance that informationrequired to be disclosed in our reports filed or submitted under the ExchangeAct is recorded, processed, summarized and reported timely.

There have been no changesin our internal controls over financial reporting (as defined in Rule 13(a)-15(f) underthe Exchange Act) that occurred during the three months ended September 30,2005 that have materially affected or are reasonably likely to materiallyaffect our internal controls over financial reporting.

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**PART II—OTHER INFORMATION**

**Item 1.**                        LegalProceedings.

We are named as adefendant, from time to time, in litigation relating to our normal businessoperations. Our management is not aware of any significant litigation, pendingor threatened, that would have a significant adverse effect on our financialposition or results of operations.

**Item 4.**                        Submissionof Matters to a Vote of Security Holders.

We held a special meeting of unitholders on October 27,2005 at which two proposals were considered. A brief description of eachproposal and the voting results follows:

Aproposal to (1) change the terms of our Class B units to provide thateach Class B unit will automatically convert into one of our common unitsand (2) issue 4,830,758 additional common units upon such conversion.

| For         |   | 7,352,663 |   |
|-------------|--------|-----------|--------|
| Against     |   | 47,964    |   |
| Abstentions |   | 31,659    |   |

 

Aproposal to approve an amendment to the Copano Energy, L.L.C. Long-TermIncentive Plan, which is referred to as the LTIP, to (i) increase thetotal number of common units authorized to be issued under the LTIP to thelesser of (a) 2,500,000 units or (b) the number of units equal to 10%of the sum of total common units outstanding and the total number of commonunits that may be issued to the holders of any outstanding equity securitiesconvertible into common units, exclusive of outstanding awards under the LTIP,determined at the time of any award, (ii) provide that not more than 30%of the total number of common units authorized to be issued under the LTIP maybe delivered in payment of restricted units and/or phantom units, (iii) designateconsultants of the Company as a class eligible for awards under the LTIP and (iv) permitthe Compensation Committee of our Board of Directors, in its discretion, todelegate any of its administrative powers under the LTIP to our Chief ExecutiveOfficer (other than with respect to grants made to executive officers anddirectors).

| For         |   | 8,623,170 |   |
|-------------|--------|-----------|--------|
| Against     |   | 137,090   |   |
| Abstentions |   | 44,484    |   |

 

**Item 6.**                        Exhibits.

Exhibits not incorporatedby reference to a prior filing are designated by an asterisk (*) and are filedherewith; all exhibits not so designated are incorporated herein by referenceto a prior filing as indicated.
| Number | ** ** | ** **                                                                                                                                                                                                                                                     | ** ** | **Description** |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------|
| 3.1    |       | Certificate of Formation  of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated  by reference to Exhibit 3.1 to Registration Statement on Form S-1  filed July 30, 2004).                                            |
| 3.2    |       | Certificate of  Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now  Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to  Registration Statement on Form S-1 filed July 30, 2004).                     |
| 3.3    |       | Second Amended  and Restated Limited Liability Company Agreement of Copano Energy, L.L.C.  (incorporated by reference to Exhibit 3.3 to Post-Effective Amendment  No. 1 to Registration Statement on Form S-1/A filed  December 15, 2004). |

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| 3.4  |   | Amendment  No. 1 to Second Amended and Restated Limited Liability Company Agreement  of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.4 to  Quarterly Report on Form 10-Q filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.5* |   | Amendment No. 2 to Second Amended and Restated  Limited Liability Company Agreement of Copano Energy, L.L.C.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| 10.1 |   | Amended and Restated Credit Agreement dated  February 13, 2004 among Copano Pipelines Group, L.L.C., Copano Field  Services/Copano Bay, L.P., Copano Field Services/Agua Dulce, L.P., Copano  Field Services/South Texas, L.P., Copano Field Services/Upper Gulf Coast,  L.P., Copano Field Services/Live Oak, L.P., Copano Field Services/Central  Gulf Coast, L.P., Copano Pipelines/South Texas, L.P., Copano Pipelines/Upper  Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P. and Copano Energy  Services/Upper Gulf Coast, L.P., as the Borrowers, and Fleet National Bank  and the other Lenders named therein (incorporated by reference to  Exhibit 10.1 to Amendment No. 2 to Registration Statement on  Form S-1/A filed October 12, 2004).                                                |
| 10.2 |   | First Amendment to Amended and Restated Credit  Agreement dated as of March 15, 2004, among Copano Pipelines Group,  L.L.C., Copano Field Services/Copano Bay, L.P., Copano Field Services/Agua  Dulce, L.P., Copano Field Services/South Texas, L.P., Copano Field  Services/Upper Gulf Coast, L.P., Copano Field Services/Live Oak, L.P., Copano  Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas, L.P.,  Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P.  and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and  Fleet National Bank and the other Lenders named therein (incorporated by  reference to Exhibit 10.2 to Amendment No. 2 to Registration  Statement on Form S-1/A filed October 12, 2004).                         |
| 10.3 |   | Second Amendment to Amended and Restated Credit  Agreement dated as of November 15, 2004, among Copano Pipelines Group,  L.L.C., Copano Field Services/ Copano Bay, L.P., Copano Field Services/Agua  Dulce, L.P., Copano Field Services/ South Texas, L.P., Copano Field  Services/Upper Gulf Coast, L.P., Copano Field Services/Live Oak, L.P., Copano  Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas, L.P.,  Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P.,  and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and  Fleet National Bank and the other Lenders named therein (incorporated by  reference to Exhibit 10.3 to Post-Effective Amendment No. 1 to  Registration Statement on Form S-1/A filed December 15,  2004). |
| 10.4 |   | Credit Agreement dated as of November 15, 2004,  by and among Copano Houston Central, L.L.C., Copano Processing, L.P. and  Copano NGL Services, L.P. as the Borrowers and Comerica Bank as the Lender  (incorporated by reference to Exhibit 10.4 to Post-Effective Amendment  No. 1 to Registration Statement on Form S-1/A filed  December 15, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| 10.5 |   | Form of  Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to  Exhibit 10.5 to Amendment No. 3 to Registration Statement on  Form S-1/A filed October 26, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.6 |   | Stakeholders’  Agreement dated July 30, 2004, by and among Copano Energy, L.L.C.,  Copano Partners, L.P., R. Bruce Northcutt, Matthew J. Assiff, EnCap Energy  Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP  Energy Partners, L.P., CEH Holdco, Inc., CEH Holdco II, Inc.,  DLJ Merchant Banking Partners III, L.P., DLJ Offshore Partners III, C.V., DLJ  Offshore Partner III-1, C.V., DLJ Offshore Partners III-2, C.V.,  DLJ Merchant Banking III, Inc., DLJ MB Partners III GmbH & Co,  KG, Millennium Partners II, L.P. and MBP III Plan Investors, L.P.  (incorporated by reference to Exhibit 10.6 to Registration Statement on  Form S-1 filed July 30, 2004).                                                                            |

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| 10.7† |   | Amended and  Restated Gas Processing Contract dated as of January 1, 2004, between  Kinder Morgan Texas Pipeline, L.P. and Copano Processing, L.P. (incorporated  by reference to Exhibit 10.7 to Amendment No. 6 to Registration  Statement on Form S-1/A filed November 5, 2004).                                                                                                                              |
|------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.8       |   | Employment Agreement between  Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling  Entities, dated April 9, 2003 (incorporated by reference to  Exhibit 10.8 to Amendment No. 2 to Registration Statement on  Form S-1/A filed October 12, 2004).                                                                                                                                             |
| 10.9       |   | First Amendment to Employment Agreement between  Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling  Entities, dated July 30, 2004 (incorporated by reference to  Exhibit 10.9 to Amendment No. 2 to Registration Statement on  Form S-1/A filed October 12, 2004).                                                                                                                          |
| 10.10      |   | Assignment and Assumption Agreement between  Copano/Operations, Inc. and CPNO Services, L.P. effective January 1,  2005 with respect to Employment Agreement between  Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling  Entities, as amended (incorporated by reference to Exhibit 10.10 to  Annual Report on Form 10-K filed March 31, 2005).                                             |
| 10.11      |   | Second Amendment to Employment Agreement between  CPNO Services, L.P., R. Bruce Northcutt and the Copano Controlling Entities,  effective March 1, 2005 (incorporated by reference to Exhibit 10.11  to Annual Report on Form 10-K filed March 31, 2005).                                                                                                                                                                  |
| 10.12      |   | Employment Agreement between  Copano/Operations, Inc. and James J. Gibson, III, dated as of  October 1, 2004 (incorporated by reference to Exhibit 10.11 to  Amendment No. 4 to Registration Statement on Form S-1/A filed  November 2, 2004).                                                                                                                                                              |
| 10.13      |   | Assignment and Assumption Agreement between  Copano/Operations, Inc. and CPNO Services, L.P. effective  January 1, 2005 with respect to Employment Agreement between  Copano/Operations, Inc. and James J. Gibson, III (incorporated by  reference to Exhibit 10.13 to Annual Report on Form 10-K  filed March 31, 2005).                                                                                   |
| 10.14      |   | First Amendment to Employment Agreement between CPNO  Services, L.P. and James J. Gibson, III, effective March 1, 2005  (incorporated by reference to Exhibit 10.14 to Annual Report on  Form 10-K filed March 31, 2005).                                                                                                                                                                                             |
| 10.15      |   | Lease Agreement  dated August 14, 2003 between Mateo Lueia and Copano Field Services/Agua  Dulce, L.P. (incorporated by reference to Exhibit 10.11 to Amendment  No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                              |
| 10.16      |   | Lease Agreement  dated January 22, 2003 between Copano/Operations, Inc., Copano  Processing, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano  Pipelines/Hebbronville, L.P. and Copano Field Services/Central Gulf Coast,  L.P. and American General Life Insurance Company (incorporated by reference  to Exhibit 10.12 to Amendment No. 2 to Registration Statement on  Form S-1 filed October 12, 2004). |
| 10.17      |   | Lease Agreement  dated as of October 17, 2000, between Plow Realty Company of Texas and  Texas Gas Plants, L.P. (incorporated by reference to Exhibit 10.13 to  Amendment No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                     |
| 10.18      |   | Lease Agreement  dated as of December 3, 1964, between The Plow Realty Company of Texas  and Shell Oil Company (incorporated by reference to Exhibit 10.14 to  Amendment No. 2 to Registration Statement on Form S-1/A filed  October 12, 2004).                                                                                                                                                                      |

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| 10.19 |   | Lease Agreement  dated as of January 1, 1944, between The Plow Realty Company of Texas  and Shell Oil Company, Incorporated (incorporated by reference to  Exhibit 10.15 to Amendment No. 2 to Registration Statement on  Form S-1/A filed October 12, 2004).                                                                                                                                                                                                                                                                                                                                                                                    |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.20 |   | Form of Restricted Unit Grant under the Copano  Energy, L.L.C. Long-Term Incentive Plan (Directors) (incorporated by  reference to Exhibit 10.1 to Current Report on Form 8-K filed  December 15, 2004).                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.21 |   | Form of Restricted Unit Grant under the Copano  Energy, L.L.C. Long-Term Incentive Plan (Employees) (incorporated by  reference to Exhibit 4.4 to Registration Statement on Form S-8  filed February 11, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.22 |   | Form of Unit Option Grant under the Copano  Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to  Exhibit 4.5 to Registration Statement on Form S-8 filed  February 11, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.23 |   | Administrative and Operating Services Agreement  dated November 15, 2004, among Copano/Operations, Inc. and Copano  Energy, L.L.C., and the Copano Operating Subsidiaries listed therein  (incorporated by reference to Exhibit 3.4 to Post-Effective Amendment  No. 1 to Registration Statement on Form S-1/A filed  December 15, 2004).                                                                                                                                                                                                                                                                                                   |
| 10.24 |   | Copano Energy, L.L.C. Management Incentive  Compensation Plan (incorporated by reference to Exhibit 10.1 to Current  Report on Form 8-K filed March 2, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.25 |   | 2005 Administrative Guidelines for the Copano  Energy, L.L.C. Management Incentive Compensation Plan (incorporated by  reference to Exhibit 10.2 to Current Report on Form 8-K filed  March 2, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 10.26 |   | Membership Interest Purchase Agreement by and among  ScissorTail Energy, LLC, Hamilton ScissorTail LLC, ScissorTail Holdings, LLC,  Jay A. Precourt, Fredric C. Hamilton, Copano Energy, L.L.C. and Copano  Energy/Rocky Mountains and Mid-Continent, L.L.C. dated as of June 20,  2005 (incorporated by reference to Exhibit 10.26 to Quarterly Report on  Form 10-Q filed August 15, 2005).                                                                                                                                                                                                                                                         |
| 10.27 |   | Class B Unit  and Common Unit Purchase Agreement dated as of June 17, 2005 by and  among Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH  Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise Energy Infrastructure  Corporation, Tortoise Energy Capital Corporation, Goldman, Sachs &  Co., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund,  Alerian Opportunity Partners LP, Alerian Capital Partners LP, Strome  HedgeCap, LP, Strome Alpha, LP and Strome Family Foundation (incorporated by  reference to Exhibit 10.27 to Quarterly Report on Form 10-Q  filed August 15, 2005). |
| 10.28 |   | Registration  Rights Agreement made and entered into as of August 1, 2005, by and  among Copano Energy, L.L.C. and Kayne Anderson MLP Investment Company, RCH  Energy MLP Fund LP, RCH Energy MLP Fund-A LP, Tortoise Energy Infrastructure  Corporation, Tortoise Energy Capital Corporation, Goldman, Sachs &  Co., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund,  Alerian Opportunity Partners LP, Alerian Capital Partners LP, Strome MLP  Fund, L.P., Strome Alpha, LP and Strome Family Foundation (incorporated by  reference to Exhibit 10.28 to Quarterly Report on Form 10-Q  filed August 15, 2005).    |
| 10.29 |   | Unitholder Voting  Agreement dated as of August 1, 2005 by and among Copano Partners Trust,  MBP III AIV, L.P., MBP Onapoc Holdings LLC, R. Bruce Northcutt and Matthew J.  Assiff (incorporated by reference to Exhibit 10.29 to Quarterly Report  on Form 10-Q filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                                              |

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| 10.30 |   | Credit Agreement  dated as of August 1, 2005 among Copano Energy, L.L.C., as the Borrower,  Bank of America, N.A., as Administrative Agent and L/C Issuer, Comerica Bank  and U.S. Bank National Association, as Co-Syndication Agents, Bank of  Scotland and Fortis Capital Corp., as Co-Documentation Agents and The Other  Lenders Party Hereto and Banc of America Securities LLC, as Sole Lead  Arranger and Sole Book Manager (incorporated by reference to  Exhibit 10.30 to Quarterly Report on Form 10-Q filed August 15,  2005). |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.31 |   | Bridge Loan Agreement dated as of August 1,  2005 among Copano Energy, L.L.C., as the Borrower, Banc of America Bridge  LLC, as Administrative Agent and The Other Lenders Party Hereto and Banc of  America Securities LLC, as Sole Lead Arranger and Sole Book Manager  (incorporated by reference to Exhibit 10.31 to Quarterly Report on  Form 10-Q filed August 15, 2005).                                                                                                                                                                 |
| 10.32 |   | Employment Agreement between CPNO Services, L.P. and  John A. Raber dated as of August 1, 2005 (incorporated by reference to  Exhibit 10.32 to Quarterly Report on Form 10-Q filed  August 15, 2005).                                                                                                                                                                                                                                                                                                                                           |
| 10.33 |   | Employment Agreement between ScissorTail Energy,  L.L.C. and Bruce Roderick dated as of August 1, 2005 (incorporated by  reference to Exhibit 10.33 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                   |
| 10.34 |   | Employment Agreement between ScissorTail Energy,  L.L.C. and Sharon Robinson dated as of August 1, 2005 (incorporated by  reference to Exhibit 10.34 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                  |
| 10.35 |   | Employment Agreement between ScissorTail Energy,  L.L.C. and Thomas Coleman dated as of August 1, 2005 (incorporated by  reference to Exhibit 10.35 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                   |
| 10.36 |   | Employment Agreement between ScissorTail Energy, L.L.C.  and Lee E. Fiegener dated as of August 1, 2005 (incorporated by  reference to Exhibit 10.36 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                                                                                                                                                                                                                  |
| 10.37 |   | Form of Unit Option Grant under the Copano  Energy, L.L.C. Long-Term Incentive Plan (ScissorTail Energy, LLC Officers)  (incorporated by reference to Exhibit 10.37 to Quarterly Report on  Form 10-Q filed August 15, 2005).                                                                                                                                                                                                                                                                                                                   |
| 10.38 |   | Form of Restricted Unit Grant under the Copano  Energy, L.L.C. Long-Term Incentive Plan (ScissorTail Energy, LLC Officers) (incorporated  by reference to Exhibit 10.38 to Quarterly Report on Form 10-Q  filed August 15, 2005).                                                                                                                                                                                                                                                                                                               |
| 10.39 |   | Form of Indemnification Agreement (incorporated  by reference to Exhibit 10.1 to Current Report on Form 8-K  filed November 2, 2005).                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.40 |   | First Amendment to Copano Energy, L.L.C. Long-Term  Incentive Plan dated October 27, 2005 (incorporated by reference to  Exhibit 10.2 to Current Report on Form 8-K filed  November 2, 2005)                                                                                                                                                                                                                                                                                                                                                    |
| 21.1  |   | List of Subsidiaries (incorporated by reference to  Exhibit 21.1 to Quarterly Report on Form 10-Q filed  August 15, 2005).                                                                                                                                                                                                                                                                                                                                                                                                                           |
| 31.1* |   | Sarbanes-Oxley Section 302 certification of  John R. Eckel, Jr. (Chief Executive Officer) for Copano Energy, L.L.C.                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 31.2* |   | Sarbanes-Oxley Section 302 certification of  Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.                                                                                                                                                                                                                                                                                                                                                                                                                                             |

56

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| 32.1* |   | Sarbanes-Oxley  Section 906 certification of John R. Eckel, Jr. (Chief Executive  Officer) for Copano Energy, L.L.C. |
|-------|--------|--------------------------------------------------------------------------------------------------------------------------------|
| 32.2* |   | Sarbanes-Oxley Section 906 certification of  Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.        |

----

*                    Filedherewith.

†                    Portions ofthis exhibit have been omitted pursuant to a request for confidentialtreatment.

57

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized, in the City of Houston,State of Texas, on November 14, 2005.

|        | COPANO ENERGY, L.L.C. |
|--------|-----------------------|
|   | By:                   | /s/ JOHN R. ECKEL, JR. |
|   |                  | John R. Eckel, Jr. |
|   |                  | *Chairman of the Board and Chief Executive Officer* |
|   | By:                   | /s/ MATTHEW J. ASSIFF |
|   |                  | Matthew J. Assiff |
|   |                  | *Senior Vice President and Chief Financial Officer* |

 

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