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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

Copano Energy, L.L.C.
(Exact Name of Registrant as Specified in Its Charter)

2727 Allen Parkway, Suite 1200
Houston, Texas 77019
(Address of Principal Executive Offices)

(713) 621-9547
(Registrant's Telephone Number, Including Area Code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

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

        There were 7,076,192 common units of Copano Energy, L.L.C. outstanding at May 13, 2005. Copano Energy, L.L.C.'s common units trade on The Nasdaq National Market under the symbol "CPNO."

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION

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Item 1. Financial Statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS' CAPITAL

(Unaudited)

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Basis of Presentation

Organization

        Copano Energy, L.L.C. ("CE"), a Delaware limited liability company, was formed in August 2001 as Copano Energy Holdings, L.L.C. ("CEH") to acquire entities owning businesses operating under the Copano name since 1992. To simplify its corporate structure, on July 27, 2004, CEH caused the merger of Copano Energy, L.L.C., a then wholly owned subsidiary of CEH, with and into CEH, with CEH being the surviving entity. In connection with the merger, CEH changed its name to Copano Energy, L.L.C.

        CE, through its wholly owned subsidiaries, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in the South Texas and Texas Gulf Coast regions (CE and its subsidiaries collectively are referred to as the "Company").

        The Company's natural gas pipelines collect natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Company's gas processing plant, utilities and industrial consumers. Natural gas shipped to the Company's gas processing plant, either on the Company's pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into mixed natural gas liquids ("NGL") and then fractionated or separated into select component NGL products, including ethane, propane, butane and natural gasoline mix and stabilized condensate. The Company also owns and operates an NGL products pipeline extending from the Company's gas processing plant to the Houston area. The Company refers to its natural gas pipeline operating subsidiaries collectively as "Copano Pipelines" and to its processing and related activities operating subsidiaries collectively as "Copano Processing."

        On November 15, 2004, the Company completed its initial public offering (the "Offering") of 5,750,000 common units, inclusive of 750,000 common units that were issued as a result of the underwriters' exercise of their over-allotment option. The common units issued in the Offering were sold at $20.00 per common unit and the net proceeds from the Offering were used (i) to redeem CE's redeemable preferred units from certain of the Company's investors existing prior to the Offering (the "Pre-Offering Investors"), (ii) to reduce existing indebtedness under the CPG Credit Agreement (as defined herein), (iii) to reduce existing indebtedness under the term loan entered into in 2001, (iv) to pay other obligations, (v) to pay expenses of the Offering and (vi) to redeem common units, on a pro rata basis, from certain Pre-Offering Investors.

Basis of Presentation and Principles of Consolidation

        The accompanying unaudited consolidated financial statements and related notes include the assets, liabilities and results of operations of the Company for each of the periods presented. Although CE, through certain subsidiaries, owns a 62.5% equity investment in Webb/Duval Gatherers ("WDG"), a Texas general partnership, the Company accounts for the investment using the equity method of accounting because the minority general partners have substantive participating rights with respect to the management of WDG. All significant intercompany accounts and transactions are eliminated in the consolidated financial statements.

        The accompanying consolidated financial statements have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, the statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of the results of operations for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have

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been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Company's Annual Report on Form 10-K for the year ended December 31, 2004.

        Copano General Partners, Inc. ("CGP"), a Delaware corporation and a wholly owned indirect subsidiary of CE, is the only entity within the consolidated group subject to federal income taxes. CGP's operations primarily include its indirect ownership of the managing general partner interest in certain of the Copano Pipelines entities. As of December 31, 2004, CGP had a net operating loss carryforward of approximately $265,000, for which a valuation allowance has been recorded. No income tax expense was recognized for the interim period presented and except for income allocated to CGP, income is taxable directly to the members holding the membership interests in CE.

        The number of common units outstanding and per common unit amounts have been restated for the three months ended March 31, 2004 to reflect the conversion or exchange of pre-Offering common units into post-Offering common units immediately prior to the completion of the Offering.

Note 2—New Accounting Pronouncements

Share-Based Payment

        In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 123 (revised 2004), or SFAS No. 123(R), "Share-Based Payment" which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board Opinion ("APB") No. 25 and generally requires the Company to measure the cost of employee services received 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 be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). The standard also requires the Company to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. The Company is required to apply SFAS No. 123(R) to all equity awards granted, modified or settled in the first fiscal year after January 1, 2006. The Company is also required to use either the "modified prospective method" or the "modified retrospective method." Under the modified prospective method, the Company must recognize compensation cost for all awards granted after the Company adopts the standard and for the unvested portion of previously granted awards that are outstanding on that date. Under the modified retrospective method, the Company must restate previously issued financial statements to recognize the amounts the Company previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. Under both methods, the Company is permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption.

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        The Company has commenced the analysis of the impact of SFAS No. 123(R), but has not yet decided: (1) whether the Company will elect early adoption, (2) if the Company elects early adoption, at what date the Company would do so, (3) whether the Company will use the modified prospective method or elect to use the modified retrospective method and (4) whether the Company will elect to use straight line amortization or an accelerated method. Additionally, the Company cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption. Accordingly, the Company cannot currently quantify with precision the effect that this standard would have on the financial position or results of operations in the future, except that the Company probably will recognize a greater expense for any awards that the Company may grant in the future than the Company would recognize using the current guidance. If the Company were to adopt SFAS No. 123(R) using the modified retrospective method, our net income would have been approximately $38,000 less than that reported for the three months ended March 31, 2005.

Exchanges of Nonmonetary Assets an amendment of APB No. 29

        In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29." This statement amends APB No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date this statement is issued. Retroactive application is not permitted. Management is analyzing the requirements of this new statement and believes that its adoption will not have any significant impact on the Company's financial position, results of operations or cash flows.

Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143

        In March 2005, the FASB issued FASB Interpretation No. ("FIN") 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143." FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, "Accounting for Asset Retirement Obligations," refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction or development or through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005. Retrospective application for interim financial information is

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permitted but is not required. Early adoption of FIN 47 is encouraged. Management of the Company is currently evaluating what impact FIN 47 will have on the Company's consolidated financial statements, but at this time, does not believe that the adoption of FIN 47 will have a significant impact on the Company's financial position, results of operations or cash flows.

Note 3—Intangible Assets

        Intangible assets consist of rights-of-way, easements and an acquired customer relationship, which the Company amortizes over the term of the agreement or estimated useful life. As of March 31, 2005 and December 31, 2004, the weighted average amortization period for the Company's intangible assets was 9.8 years and 10.1 years, respectively. Amortization expense was $107,000 for each of the three months ended March 31, 2005 and 2004. Estimated aggregate amortization expense remaining for each of the succeeding fiscal years and thereafter is approximately: 2005—$322,000; 2006—$419,000; 2007—$379,000; 2008—$312,000; 2009—$244,000; and thereafter—$2,744,000. Intangible assets consisted of the following (in thousands):

Note 4—Long-Term Debt

        A summary of the Company's debt follows (in thousands):

CPG Credit Agreement

        Copano Pipelines Group, L.L.C. ("CPG"), a wholly owned subsidiary, and certain of Copano Pipelines' operating subsidiaries have a $100.0 million revolving credit agreement (the "CPG Credit Agreement"), which matures on February 12, 2008. The balance outstanding under the CPG Credit Agreement totaled $45,000,000 and $48,000,000 as of March 31, 2005 and December 31, 2004, respectively. Future borrowings under this revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. This revolving credit facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders.

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        The CPG credit facility is available to be drawn on and repaid without restriction so long as CPG is in compliance with the terms of the CPG Credit Agreement, including certain financial covenants. Based upon the senior debt to EBITDA (as defined) ratio calculated as of March 31, 2005 (utilizing trailing four quarters' EBITDA), CPG had approximately $30,747,000 of unused capacity under the CPG Credit Agreement. Management believes that CPG and its subsidiaries are in compliance with the financial covenants under the CPG Credit Agreement as of March 31, 2005. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies.

        The effective average interest rate on borrowings under the CPG Credit Agreement was 5.9% and 5.4% as of March 31, 2005 and December 31, 2004, respectively. The quarterly commitment fee on the unused portion of the credit facility was 0.5% at March 31, 2005 and December 31, 2004. Interest and other financing costs related to the CPG Credit Agreement totaled $886,000 and $574,000 for the three months ended March 31, 2005 and 2004, respectively. Costs incurred in connection with the establishment of this facility and subsequent amendments are being amortized over the remaining term of the CPG Credit Agreement, and as of March 31, 2005 and December 31, 2004, the unamortized portion of debt issue costs totaled $1,664,000 and $1,736,000, respectively.

CHC Facility

        Concurrent with the closing of the Offering, on November 15, 2004, Copano Houston Central, L.L.C. ("CHC"), a wholly owned subsidiary, and certain of its subsidiaries entered into a $12 million secured revolving credit facility (the "CHC Facility") with Comerica Bank due January 31, 2007. The balance outstanding under the CHC Facility totaled $8,000,000 and $9,000,000 as of March 31, 2005 and December 31, 2004, respectively. CHC expects to use amounts available under this credit facility to finance capital expenditures (including construction and expansion projects) as well as to meet working capital requirements of its processing operations. The CHC Facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders.

        The effective average interest rate on borrowings under the CHC Facility was 5.3% and 4.8% as of March 31, 2005 and December 31, 2004, respectively. The quarterly commitment fee on the unused portion of the credit facility was 0.3% at March 31, 2005 and December 31, 2004. Interest and other financing costs related to the CHC Facility totaled $137,000 for the three months ended March 31, 2005. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the CHC Facility, and as of March 31, 2005 and December 31, 2004, the unamortized portion of debt issue costs totaled $165,000 and $188,000, respectively.

        Management believes that CHC and its subsidiaries are in compliance with the covenants under the CHC Facility as of March 31, 2005. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies.

Note 5—Members' Capital and Distributions

Common Units and Subordinated Units

        As of March 31, 2005, 10,585,318 units were outstanding, comprised of 7,066,192 common units and 3,519,126 subordinated units. Pre-Offering Investors owned an aggregate of 1,288,252 common units,

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employees and board members owned an aggregate 27,940 restricted common units and the public owned an aggregate of 5,750,000 common units. Pre-Offering Investors and their assignees owned all of the outstanding subordinated units.

        Pursuant to the limited liability company agreement, our Pre-Offering Investors have agreed to reimburse the Company for general and administrative expenses in excess of stated levels (subject to certain limitations) for a period of three years beginning on January 1, 2005. Specifically, to the extent general and administrative expenses exceed certain levels, the portion of the general and administrative expenses ultimately funded by the Company (subject to certain adjustments and exclusions) will be limited, or capped. For the year ended December 31, 2005, the "cap" limits the Company's general and administrative expense obligations to $1.5 million per quarter (subject to certain adjustments and exclusions). During this three-year period, the quarterly limitation on general and administrative expenses 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-Offering Investors made capital contributions to the Company in the aggregate amount of $1,424,000 as a reimbursement of excess general and administrative expenses for the three months ended March 31, 2005. The Pre-Offering Investors used escrowed funds that the Company had distributed to them prior to the Offering to make these contributions.

Restricted Units

        A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. In addition, restricted units will vest upon a change in control of CE, unless provided otherwise by the compensation committee. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted units. The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive and CE will receive no remuneration for the units.

        During the three months ended March 31, 2005, CE awarded 9,940 restricted common units to employees with an intrinsic value of $270,000. Each of these restricted unit grants vests in equal one-fourth annual installments commencing on the first anniversary of the grant date or upon a change of control, death, disability or, in certain circumstances, retirement and the intrinsic value of the units is amortized into general and administrative expense over the vesting period. The Company recognized expense of $83,000 related to the amortization of restricted units outstanding during the three months ended March 31, 2005.

Distributions

        The holders of the common and subordinated units are entitled to participate in distributions. The common units have the right to receive a minimum quarterly distribution of $0.40 per unit, plus any arrearages on the common units, before any distribution is made to the holders of the subordinated units. Subordinated units do not accrue distribution arrearages. After the expiration of the subordination period, common units will no longer be entitled to arrearages.

        On January 18, 2005, the Board of Directors declared an adjusted cash distribution for the partial period from the closing of the Offering on November 15, 2004 through December 31, 2004 of $0.20 per

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unit for all outstanding common and subordinated units. The distribution totaling $2,115,000 was paid on February 14, 2005 to holders of record at the close of business on February 1, 2005.

        On April 15, 2005, the Board of Directors declared and the Company paid a cash distribution of $533,000 to certain Pre-Offering Investors for reimbursement of their respective tax obligations attributable 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 the Offering.

        On April 18, 2005, the Board of Directors declared a cash distribution for the three months ended March 31, 2005 of $0.42 per unit for all of its outstanding common and subordinated units. The distribution totaling $4,446,000 was paid on May 13, 2005 to holders of record at the close of business on May 2, 2005.

Unit Options

        Unit options will have an exercise price that may not be less than the fair market value of the underlying units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, unit options will become exercisable upon a change in control of CE, unless provided otherwise by the compensation committee.

        During the three months ended March 31, 2005, CE granted 28,690 unit options to purchase an equal number of common units at $27.05 per unit and 2,220 unit options to purchase an equal number of common units at $28.96 per unit to certain employees. These unit options will vest in five equal annual installments commencing with the first anniversary of the grant date or will become exercisable upon a change of control, death or disability. Outstanding options have remaining contractual lives of approximately 10 years at March 31, 2005.

        A summary of the unit option activity for the three months ended March 31, 2005 is provided below:

Accounting for Stock-Based Compensation

        The Company uses the intrinsic value method established by APB No. 25, "Accounting for Stock Issued to Employees" to value unit options issued to employees under the Company's long-term incentive plan adopted on November 15, 2004. In accordance with APB No. 25 for fixed unit options, compensation is recorded to the extent the fair value of the unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. For the three months ended March 31, 2005, the cost of this

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stock-based compensation program had no impact on the Company's net income, as all options granted had an exercise price equal to the market value of the underlying common unit on the date of grant.

        If compensation expense related to the issuance of the options had been determined by applying the fair value method prescribed in SFAS No. 123, the Company's net income (loss) and net income (loss) per equivalent unit would have approximated the pro forma amounts below (in thousands):

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

        The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions for 2005 (no options were granted during the three months ended March 31, 2004): weighted average exercise price of $27.19, expected volatility rate of 24.53%, risk-free interest rate of 4% and expected life of seven years. The Black-Scholes weighted average fair value of options granted in 2005 was $3.35 per unit.

Note 6—Net Income (Loss) Per Unit

        Basic net income (loss) per equivalent unit excludes dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of equivalent units outstanding during the period. Dilutive net income (loss) per equivalent unit reflects potential dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of equivalent units outstanding during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been exercised.

        Basic net income (loss) per equivalent unit is calculated as follows (in thousands, except per unit amounts). For periods prior to the Offering, equivalent units were calculated using the weighted average of pre-Offering common units and common special units adjusted by a conversion or exchange factor to

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reflect the exchange of pre-Offering common units and common special units for post-Offering common units immediately prior to completion of the Offering.

*

CE had 58,722 dilutive employee unit options outstanding during the three months ended March 31, 2005. The 3,750,000 potentially dilutive warrants that were outstanding during the three months ended March 31, 2004 and previously held by preferred unitholders were excluded from the dilutive loss per equivalent unit calculation because to include these equity securities would have been anti-dilutive since the Company reported a net loss for the three months ended March 31, 2004.

        Net loss per unit for the three months ended March 31, 2004 has not been presented for junior units and junior special units as such units were not entitled to share in earnings for this period.

Note 7—Related Party Transactions

Operations Services

        Through December 31, 2004, the Company did not directly employ any persons to manage or operate its business other than certain Delaware-based officers. With respect to the Texas operating subsidiaries of the Company, Copano/Operations, Inc. ("Copano Operations"), an entity controlled by John R. Eckel, Jr., Chairman of the Board of Directors and Chief Executive Officer of the Company, provided management, operations and administrative support services for the Company. The Company reimbursed Copano Operations for all direct and indirect costs of these services. Copano Operations charged these subsidiaries, without markup, based upon total monthly expenses incurred by Copano Operations less (i) a fixed allocation to reflect expenses incurred by Copano Operations for the benefit of certain entities controlled by Mr. Eckel and (ii) any costs to be charged directly to an entity for which Copano Operations performed services. Management believes that this methodology was reasonable. Effective January 1, 2005 and pursuant to a general and administrative services agreement with Copano Operations, Copano Operations transferred responsibility to CPNO Services, L.P., an indirect wholly owned subsidiary of CE, for a significant portion of the services, including its employment of certain employees on the Company's behalf, that Copano Operations had previously provided to the Company. Under the general and administrative services agreement, the Company continues to reimburse Copano Operations for all direct and indirect costs of the services provided to the Company by Copano Operations using the same methodology as utilized prior to January 1, 2005. Management believes that this methodology is reasonable. For the three months ended March 31, 2005 and 2004, the Company reimbursed Copano Operations $778,000 and $3,302,000, respectively, for administrative and operating costs, including payroll and benefits expense for both field and administrative personnel of the Company. These costs are included in operations and maintenance expenses and general and administrative expenses on the consolidated

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statements of operations. As of March 31, 2005, amounts payable by the Company to Copano Operations were $81,000.

        Management estimates that these expenses on a stand-alone basis (that is, the cost that would have been incurred by the Company to conduct current operations if the Company had obtained these services from an unaffiliated entity) would not be significantly different from the amounts recorded in the Company's consolidated financial statements for each of the three months ended March 31, 2005 and 2004.

Natural Gas Transactions

        During the three months ended March 31, 2005 and 2004, the Company purchased natural gas from affiliated companies of Mr. Eckel totaling $262,000 and $395,000, respectively, and provided gathering and compression services to affiliated entities of Mr. Eckel totaling $11,000 and $17,000, respectively. Additionally, affiliated companies of Mr. Eckel reimbursed the Company $18,000 and $9,000 for the three months ended March 31, 2005 and 2004, respectively, in gas lift costs which are reflected as a reduction of operations and maintenance expense in the consolidated statements of operations. Management believes these purchases and sales were on terms no less favorable than those that could have been achieved with an unaffiliated entity. As of March 31, 2005, amounts payable by the Company to affiliated companies of Mr. Eckel, other than Copano Operations, totaled $70,000.

        The Company paid WDG for transportation and purchased natural gas from WDG. Natural gas purchases and transportation totaled $303,000 and $445,000 for the three months ended March 31, 2005 and 2004, respectively. Additionally, as operator of WDG, a subsidiary of CE charges WDG a monthly administrative fee of $16,000 and has made advances to WDG for capital expenditures. As of March 31, 2005, the Company's net receivable from WDG totaled $1,276,000.

Other

        A subsidiary of Merrill Corporation ("Merrill"), an affiliate of Credit Suisse First Boston Private Equity which held an interest in the Company as of March 31, 2005, provided the Company with printing and distribution services in connection with the Offering and continues to provide assistance with printing and on-going public filings. For the three months ended March 31, 2005 and 2004, the Company incurred $7,000 and $0, respectively, of printing, distribution and filing costs from Merrill. Management believes that the Company obtained these services on terms no less favorable than those that could have been achieved with an unaffiliated entity.

Note 8—Commitments and Contingencies

Commitments

        For the three months ended March 31, 2005 and 2004, rental expense for office space, leased vehicles and leased compressors and related field equipment used in the Company's operations totaled $230,000 and $507,000, respectively.

        The Company has both fixed and variable quantity contractual commitments arising in the ordinary course of its natural gas marketing activities. At March 31, 2005, the Company had fixed contractual commitments to purchase 493,500 million British thermal units ("MMBtu") of natural gas in April 2005. As of March 31, 2005, the Company had fixed contractual commitments to sell 2,431,500 MMBtu of

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natural gas in April 2005. All of these contracts are based on index-related market pricing. Using index-related market prices as of March 31, 2005, total commitments to purchase natural gas related to such agreements equaled $3,490,000 and the total commitment to sell natural gas under such agreements equaled $16,766,000. The Company's commitments to purchase variable quantities of natural gas at index-based prices range from contract periods extending from one month to the life of the dedicated production. During March 2005, natural gas volumes purchased under such contracts equaled 4,388,790 MMBtu. The Company's commitments to sell variable quantities of natural gas at index-based prices range from contract periods extending from one month to 2012. During March 2005, natural gas volumes sold under such contracts equaled 416,124 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 certain instances, this interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

        From July 8, 2002 through April 1, 2004, the Company guaranteed certain vehicle lease obligations of Copano Operations for vehicles operated for the benefit of certain of Copano operating entities. Effective as of April 2, 2004, the vehicle leases were transferred by Copano Operations to Copano Pipelines/Hebbronville, L.P. ("Hebbronville"), an indirect wholly owned subsidiary of CE, and Hebbronville, as lessee, guarantees the lessor a minimum residual sales value upon the expiration of the lease and sale of the underlying vehicle. Certain of the Copano Pipelines entities currently guarantee the lease payment obligations, including the residual sales value. As of March 31, 2005, the Company guaranteed $368,000 related to these lease payment obligations. As of March 31, 2005, aggregate guaranteed residual values for vehicles under these operating leases were as follows (in thousands):

        Effective April 12, 2003, the Company has guaranteed certain telephone equipment lease obligations (approximately $20,000 of lease payment obligations as of March 31, 2005) of Copano Operations. Prior to January 1, 2005, the use of this telephone equipment by the Company was included in the support services provided by Copano Operations to the Company. See Note 6. The Company anticipates that the obligations under this lease will be transferred to the Company.

        Presently, neither the Company nor any of its subsidiaries have any other types of guarantees outstanding that require liability recognition under the provisions of FIN 45.

        FIN 45 also sets forth disclosure requirements for guarantees by a parent company on behalf of its subsidiaries. CE or a subsidiary entity, from time to time, may issue parent guarantees of commitments resulting from the ongoing activities of subsidiary entities. Additionally, a subsidiary entity may from time to time issue a guarantee of commitments resulting from the ongoing activities of another subsidiary entity. The guarantees generally arise in connection with a subsidiary commodity purchase obligation, subsidiary lease commitments and subsidiary bank debt. The nature of such guarantees is to guarantee the performance of the subsidiary entities in meeting their respective underlying obligations. Except for operating lease commitments, all such underlying obligations are recorded on the books of the subsidiary

17

entities and are included in the consolidated financial statements as obligations of the combined entities. Accordingly, such obligations are not recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary entity. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary entity. As of March 31, 2005, the approximate amount of parental guaranteed obligations were as follows (in thousands):

Regulatory Compliance

        In the ordinary course of business, the Company is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position of the Company.

Litigation

        The Company is named as a defendant, from time to time, in litigation relating to its normal business operations. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on the Company's financial position or results of operations.

Note 9—Supplemental Disclosures to the Statements of Cash Flows

Cash paid during each of the periods presented (in thousands)

        Supplemental disclosures of noncash investing and financing activities (in thousands)

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Note 10—Segment Information

        Based on the Company's approach to managing its assets, the Company believes its operations consist of two segments: (i) gathering, transportation and marketing of natural gas (Copano Pipelines) and (ii) natural gas processing and related NGL transportation (Copano Processing). The Company currently reports its operations, both internally and externally, using these two segments. The Company evaluates segment performance based on segment margin before depreciation and amortization. All of the Company's revenue is derived from, and all of the Company assets and operations are located in, the South Texas and Texas Gulf Coast regions of the United States. Transactions between reportable segments are conducted on an arm's length basis.

        Summarized financial information concerning the Company's reportable segments is shown in the following table (in thousands):

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

        You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited consolidated financial statements and notes thereto included elsewhere in this report. References in this Item 2 to "Copano Energy, 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 this report, the following terms have the following meanings:

Overview

        We are a Delaware limited liability company formed in 2001 to acquire entities operating under the Copano name since 1992 and to serve as a holding company for our operating subsidiaries. On November 15, 2004, we completed our initial public offering of 5,750,000 common units at a price of $20.00 per unit, inclusive of 750,000 common units which were issued as a result of the underwriters' exercise of their over-allotment option. Net proceeds from the sale of the units totaled $106.95 million.

        We own networks of natural gas gathering and intrastate pipelines in the Texas Gulf Coast region. Our natural gas processing plant is the second largest in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. The plant is located approximately 100 miles southwest of Houston, Texas.

        We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into two business segments, Copano Pipelines and Copano Processing.

•

Copano Pipelines is engaged in the gathering and intrastate transmission of natural gas in areas we refer to as the South Texas, Coastal Waters, Central Gulf Coast and Upper Gulf Coast regions. Within this segment, we also provide certain related services including compression, dehydration and marketing of natural gas. For the three months ended March 31, 2005 and 2004, this segment generated approximately 55% and 74%, respectively, of our total gross margin.



•

Copano Processing is engaged in natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central Processing Plant and Sheridan NGL Pipeline. For the three months ended March 31, 2005 and 2004, this segment generated approximately 45% and 26%, respectively, of our total gross margin.

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

        Our segment gross margins are determined primarily by four interrelated variables: (1) the volume of natural gas gathered or transported through our pipelines, (2) the volume of natural gas processed, conditioned or treated at our Houston Central Processing Plant, (3) the level and relationship of natural gas and NGL prices and (4) our current contract portfolio. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and

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NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

        The margins we realize from a significant portion of the natural gas that we gather or transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins on such natural gas volumes are based on a percentage of the index price. The profitability of our processing operations is dependent upon the relationship between natural gas and NGL prices. When natural gas prices are low relative to NGL prices, it is more profitable for us to process natural gas than to condition it. Conversely, when natural gas prices are high relative to NGL prices, processing is less profitable or unprofitable. During such periods, we have the flexibility to condition natural gas rather than fully process it. Conditioning natural gas, however, is less profitable than processing during periods when the value of recovered NGLs exceeds the value of natural gas required for plant fuel and to replace the reduced Btus that result from processing the natural gas.

How We Evaluate Our Operations

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

        Throughput Volumes.    Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes on our pipelines to ensure that we have adequate throughput to meet our financial objectives. It is important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes that are attached to those systems. Our performance at the Houston Central Processing Plant is significantly influenced by both the volume of natural gas coming into the plant and the NGL content of the natural gas. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs associated with our pipeline operations, these costs are frequently passed on to our producers.

        Segment Gross Margin.    We define segment gross margin as our revenue less cost of sales. Cost of sales includes the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs purchased by us from affiliates, costs we pay third parties to transport our volumes and costs we pay our affiliates to transport our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. The segment gross margin data reflect the financial impact on our company of our contract portfolio. With respect to our Copano Pipelines segment, our management analyzes segment gross margin per unit of volumes gathered or transported. With respect to our Copano Processing segment, our management also analyzes segment gross margin per unit of natural gas processed or conditioned and the segment gross margin per unit of NGLs recovered. Our segment gross margin is reviewed monthly for consistency and trend analysis.

        To isolate and consistently track changes in commodity price relationships and their impact on our processing segment's results, we calculate a hypothetical "standardized" processing margin. This processing margin is based on a fixed set of assumptions, with respect to liquids composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our financial results are not derived from this standardized processing margin and the standardized margin is not derived from our financial results. However, we believe this calculation is representative of our current operating commodity price environment and we use this calculation to track commodity price relationships. Our results of operations may not necessarily correlate

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to the changes in our standardized processing margin because of the impact of factors other than commodity prices such as volumes, changes in NGL composition, recovery rates and variable contract terms. Our standardized processing margins averaged $0.14 per gallon during the first quarter of 2005 compared to $0.08 per gallon during the first quarter of 2004. The average standardized processing margin for the period from 1989 through March 31, 2005 is $0.09 per gallon.

        Operations and Maintenance Expenses.    Operations and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, insurance, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operations and maintenance expenses. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. A portion of our operations and maintenance expenses are incurred through Copano Operations, an affiliate of our company. Under the terms of our arrangement with Copano Operations, we will reimburse it, at cost, for the operations and maintenance expenses it incurs on our behalf. Effective January 1, 2005 and pursuant to our general and administrative services agreement with Copano Operations, Copano Operations transferred responsibility to us for a significant portion of the services, including certain operating and maintenance services, that it had previously provided to us.

        General and Administrative Expenses.    Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. Substantially all of our general and administrative expenses were incurred through Copano Operations, an affiliate of our company, through December 31, 2004. Effective January 1, 2005 and pursuant to our general and administrative services agreement with Copano Operations, Copano Operations transferred responsibility to us for a significant portion of the services, including certain general and administrative services, that it had previously provided to us.

        Pursuant to our limited liability company agreement, our Pre-Offering Investors have agreed to reimburse us for our general and administrative expenses in excess of stated levels (subject to certain limitations) for a period of three years beginning on January 1, 2005. Specifically, to the extent our general and administrative expenses exceed the following levels, the portion of the general and administrative expenses ultimately funded by us (subject to certain adjustments and exclusions) will be limited, or capped, as indicated:

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

        Immediately prior to completion of the Offering, we distributed to our Pre-Offering Investors $4 million. Our Pre-Offering Investors deposited these funds in escrow accounts to be used for the purpose of satisfying their respective general and administrative expense reimbursement obligation. If the escrow accounts are exhausted, any further reimbursement obligation will be limited to the amount of the distributions attributable to the common and subordinated units owned by the Pre-Offering Investors

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immediately prior to our Offering. On May 12, 2005, Pre-Offering Investors made a capital contribution to us in the aggregate amount of $1.4 million as a reimbursement of excess general and administrative expenses for the three months ended March 31, 2005 using these escrowed funds.

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

•

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



•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;



•

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and



•

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

        EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders and is used to compute our financial covenants under our credit facilities. EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

        Distributable Cash Flow:    We define distributable cash flow as net income or loss plus: (1) depreciation and amortization expense; (2) cash distributions received from investments in unconsolidated affiliates less equity in the earnings of such unconsolidated affiliates; (3) reimbursements by our Pre-Offering Investors of certain general and administrative expenses in excess of the "G&A Cap" defined in our limited liability agreement; (4) the subtraction of maintenance capital expenditures; and (5) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period. Maintenance capital expenditures represent capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our board of directors) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity can pay to a unitholder).

How We Manage Our Operations

        Our management team uses a variety of tools to manage our business. These tools include: (1) our processing and conditioning economic model; (2) flow and transaction monitoring systems; (3) producer activity evaluation and reporting; and (4) imbalance monitoring and control.

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        Our Processing and Conditioning Economic Model.    We utilize a processing and conditioning economic model to determine whether we should process or condition natural gas at our Houston Central Processing Plant. This model allows management to analyze whether current natural gas and NGL pricing supports operating our Houston Central Processing Plant at full processing mode or whether it is economically more advantageous to operate the plant in a conditioning mode.

        Flow and Transaction Monitoring Systems.    We utilize proprietary systems that track commercial activity on each of our pipelines and monitor the flow of natural gas on our pipelines. For example, we designed and implemented software that tracks each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our 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 and respond to changes in pipeline operating conditions from our corporate office.

        Producer Activity Evaluation and Reporting.    We monitor the producer drilling and completion activity in our areas of operation to identify anticipated changes in production and potential new well attachment opportunities. The continued attachment of natural gas production to our pipeline systems is critical to our business and directly impacts our financial performance. Using a third-party electronic reporting system, we receive daily reports of new drilling permits and completion reports filed with the state regulatory agency that governs these activities. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel at our corporate office. These processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines.

        Imbalance Monitoring and Control.    We continually monitor volumes received and volumes delivered on behalf of third parties to ensure we remain within acceptable imbalance limits during the calendar month. We seek to reduce imbalances because of the inherent commodity price risk that results when receipts and deliveries of natural gas are not balanced concurrently. We have implemented "cash-out" provisions in many of our transportation agreements to reduce this commodity price risk. Cash-out provisions require that any imbalance that exists between a third party and us at the end of a calendar month is settled in cash based upon a pre-determined pricing formula. This provision ensures that imbalances under such contracts are not carried forward from month-to-month and revalued at higher or lower prices.

Our Growth Strategy

        Our growth strategy contemplates complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. We intend to pursue acquisitions and capital expenditure projects that we believe will allow us to capitalize on our existing infrastructure, personnel and relationships with producers and customers to provide midstream services. In the future, we intend to pursue selected acquisitions in new geographic areas, including other areas of Texas, Louisiana, Oklahoma and the Gulf of Mexico, to the extent they present growth opportunities similar to those we are pursuing in our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms. We intend to finance future acquisitions primarily by using the capacity available under our bank credit facilities and equity or debt offerings or a combination of both. For a more detailed discussion of our capital resources, please read "—Liquidity and Capital Resources."

        Acquisition Analysis.    In analyzing a particular acquisition we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets, strategic fit of the asset in relation to our business strategy, expertise required to manage the asset, capital required to integrate and

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maintain the asset, and the competitive environment of the area where the assets are located. From a financial perspective, we analyze the rate of return the assets will generate under various case scenarios, comparative market parameters and the additive earnings and cash flow capabilities of the assets.

        Capital Expenditure Analysis.    We make capital expenditures either to maintain our assets or the supply of natural gas volumes to our assets or for expansion projects to increase our gross margin. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. Our decisions whether to spend capital on expansion projects are generally based on anticipated earnings, cash flow and rate of return of the assets.

Forward-Looking Statements

        This report contains certain "forward-looking statements" within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this report, including, but not limited to, those under "—Our Results of Operations" and "—Liquidity and Capital Resources" are forward-looking statements. Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "expect," "anticipate," "estimate," "continue," or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

•

Our ability to successfully purchase and integrate any future acquired assets or operations;



•

The volatility of prices and market demand for natural gas and natural gas liquids;



•

Our ability to continue to obtain new sources of natural gas supply;



•

Our ability to retain our key producers;



•

Our ability to retain our key customers;



•

General economic conditions;



•

The effects of government regulations and policies; and



•

Other financial, operations and legal risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission.

        Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, including without limitation in conjunction with the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2004, and in this report in "Management's Discussion and Analysis of Financial Condition and Results of Operations." All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Our Results of Operations

(1)

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

(2)

Excludes results and volumes associated with our interest in Webb/Duval Gatherers. Gross volumes transported by Webb/Duval Gatherers were 128,861 MMBtu/d and 113,113 MMBtu/d, net of intercompany volumes, for the three months ended March 31, 2005 and 2004, respectively.

(3)

Represents the total processing segment gross margin divided by the total inlet throughput or NGLs produced, as appropriate.

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Three Months Ended March 31, 2005 Compared with Three Months Ended March 31, 2004

        Pipelines Segment Gross Margin.    Pipelines segment gross margin was $7.9 million for the three months ended March 31, 2005 compared to $7.3 million for the three months ended March 31, 2004, an increase of $0.6 million, or 8%. The increase was primarily attributable to higher average natural gas prices during the three months ended March 31, 2005 compared to the three months ended March 31, 2004, which resulted in an increase in margins associated with our index price-related gas purchase and transportation arrangements. During the first quarter of 2005, the Houston Ship Channel, or HSC, natural gas index price averaged $5.82 per MMBtu compared to $5.31 per MMBtu during the first quarter of 2004, an increase of $0.51, or 10%. Additionally, a portion of the increase in gross margin for our pipeline segment resulted from the acquisitions of our Karnes County Gathering System in September 2004 and our Runge Gathering System in December 2004 and improved contract terms.

        Processing Segment Gross Margin.    Processing segment gross margin was $6.6 million for the three months ended March 31, 2005 compared to $2.5 million for the three months ended March 31, 2004, an increase of $4.1 million, or 164%. For the three months ended March 31, 2005, we experienced improvements of $5.2 million in our processing segment gross margin as the result of increased plant utilization and an improved commodity price environment. For a discussion of the commodity price environment, please read "—How We Evaluate Our Operations—Segment Gross Margin." Our processing segment gross margin was further improved during the first quarter of 2005 as compared to the first quarter of 2004 as a result of increased conditioning fee revenue of $0.4 million. This increased processing segment gross margin was partially offset by an increase in processing upgrade payments of $1.5 million to natural gas suppliers, including our pipeline affiliates, during the first quarter of 2005 as compared to the first quarter in 2004.

        Operations and Maintenance Expenses.    Operations and maintenance expenses totaled $3.0 million for each of the three months ended March 31, 2005 and 2004. Lower compression rental expense of $0.3 million during the three months ended March 31, 2005 as a result of our purchase of certain compression equipment in our South Texas Region that had previously been leased by us during 2004 was offset by higher repair and maintenance expense totaling $0.2 million and increased salaries and benefits for our field employees of $0.1 million.

        Depreciation and Amortization.    Depreciation and amortization totaled $1.8 million for the three months ended March 31, 2005 compared with $1.6 million for the three months ended March 31, 2004, an increase of $0.2 million, or 13%. This increase relates primarily to additional depreciation and amortization associated with capital expenditures made after March 31, 2004, including the purchase of compression equipment in 2004, the purchase and modification of the Karnes County Gathering System during the third quarter of 2004 and modifications and enhancements made to the Runge Gathering System during the fourth quarter of 2004.

        General and Administrative Expenses.    General and administrative expenses totaled $3.4 million for the three months ended March 31, 2005 compared with $1.7 million for the three months ended March 31, 2004, an increase of $1.7 million, or 100%. The increase was primarily due to costs of becoming a public company including (i) costs of preparing and processing tax K-1s to unitholders of $0.3 million, (ii) costs associated with accounting, legal, director compensation, investor relations, Sarbanes-Oxley readiness and insurance of $0.5 million and (iii) costs related to augmented infrastructure and hiring additional staff of $0.7 million. Additionally, we incurred $0.2 million related to growth and acquisition initiatives during the three months ended March 31, 2005.

        Interest Expense.    Interest and other financing costs totaled $1.0 million for the three months ended March 31, 2005 compared with $4.1 million for the three months ended March 31, 2004. Interest expense related to our credit facilities totaled $0.9 million and $0.5 million for the three months ended March 31, 2005 and 2004, respectively. Average borrowings under these credit facilities were $55.0 million and $43.9 million with average interest rates of 5.8% and 3.6% for the first quarter 2005 and 2004, respectively.

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Amortization of debt issue costs totaled $0.2 million and $0.6 million for the three months ended March 31, 2005 and 2004, respectively. Amortization of debt issue cost for the three months ended March 31, 2004 included a one-time charge of $0.3 million related to the early termination of the then outstanding Copano Processing credit facility. Additionally, interest expense for the three months ended March 31, 2004 included $3.0 million of interest related to the payment-in-kind units issued to certain Pre-Offering Investors that held the redeemable preferred units, the accretion of the allocated warrant value associated with the redeemable preferred units and payment-in-kind interest under a term loan entered into in 2001. The decrease in interest expense is due primarily to our redemption of the redeemable preferred units and the payment of the remaining balance due under the term loan with the net proceeds from the Offering in November 2004.

Impact of Inflation

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

Liquidity and Capital Resources

        Cash generated from operations, borrowings under our credit facilities and funds from equity and debt offerings are our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

        Off-Balance Sheet Arrangements.    We had no off-balance sheet arrangements as of March 31, 2005.

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

•

maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and



•

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

        Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider a variety of assets for potential acquisitions. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read "—Our Growth Strategy—Acquisition Analysis."

        During the three months ended March 31, 2005, our capital expenditures totaled $1.1 million, consisting of $0.5 million of expansion capital and $0.6 million of maintenance capital. We funded our capital expenditures with funds from operations. The majority of the expansion capital expenditures relate to completing the integration of the Runge Gathering System and constructing well interconnections to attach volumes in new areas. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our credit facilities and the issuance of additional equity or debt as

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appropriate given market conditions. We anticipate expending $3.0 million to $4.0 million of maintenance capital over the next 12 months.

        Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, 2005 is as follows:

        In addition to the contractual obligations noted in the table above, we have both fixed and variable quantity contracts to purchase natural gas, which were executed in connection with our natural gas marketing activities. As of March 31, 2005, we had fixed contractual commitments to purchase 493,500 MMBtu of natural gas in April 2005. All of these contracts were based on index-related prices. Using these index-related prices at March 31, 2005, we had total commitments to purchase $3.5 million of natural gas under such agreements. Our contracts to purchase variable quantities of natural gas at index-related prices range from one month to the life of the dedicated production. During March 2005, we purchased 4,388,790 MMBtu of natural gas under such contracts.

        Cash Flows.    The following summarizes our cash flows for the three months ended March 31, 2005 and 2004.

Operating:

        The overall increase of $8.8 million in operating cash flow for the three months ended March 31, 2005 compared to the three months ended March 31, 2004 was primarily the result of an increase in net income

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of $6.0 million, a decrease in non-cash items of $3.1 million and an increase in the changes in working capital components (exclusive of cash and cash equivalents) of $5.9 million. This increase in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of a decrease in accounts receivable of $7.7 million that was partially offset by a decrease in accounts payable of $2.1 million.

        We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our revolving credit facilities, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our credit facilities, and the issuance of additional equity and debt securities, as appropriate. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

        Investing:    Net cash used in investing activities was $1.1 million for the three months ended March 31, 2005 compared to $1.0 million for the three months ended March 31, 2004. Capital expenditures for 2005 include costs relate to completing the integration of the Runge Gathering System, building well interconnections, constructing a monitoring and control system for our NGL line and upgrading dehydration facilities at the inlet to the cryogenic portion of our Houston Central Processing Plant. Capital expenditures in 2004 include expenditures for the acquisition of compression equipment and the development and installation of our SCADA system.

        Financing:    Net cash used in financing activities totaled $6.2 million during the three months ended March 31, 2005 and included repayments under our credit facilities of $4.0 million, distributions to our unitholders of $2.1 million and deferred financing costs of $0.1 million. Net cash provided by financing activities of $1.0 million during the three months ended March 31, 2004 was primarily attributable to our net borrowings, including the release of restricted cash, of $3.0 million in long-term debt offset by deferred financing costs of $1.5 million and deferring Offering costs of $0.5 million.

        Cash Distributions and Reserves:    Within 45 days after the end of each quarter, we intend to pay quarterly in arrears (in February, May, August and November of each year), to the extent we have sufficient available cash from operating surplus as defined in our limited liability company agreement, no less than the minimum quarterly distribution, or MQD, of $0.40 per unit (or $1.60 per year), to our common and subordinated unitholders of record on the applicable record date. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the MQD of $0.40 per quarter, plus any arrearages in the payment of the MQD on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less retained cash reserves that our board determines are necessary to a) provide for the proper conduct of our business; b) comply with applicable law, any of our debt instruments, or other agreements; or (c) provide funds for distributions to our unitholders for any one or more of the next four quarters; plus all cash on hand for the quarter resulting from eligible working capital borrowings made after the end of the quarter on the date of determination of available cash. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus eligible working capital borrowings after the end of the quarter, plus $12.0 million, as adjusted for reserves. We have not established a credit facility that provides for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders.

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        Our board has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any of our agreements or obligations.

        On February 14, 2005, we paid cash distributions of $2.1 million, or $0.20 per unit, which reflected a pro rata portion of our MQD for the period from November 15, 2004, the closing of the Offering, through December 31, 2004. Additionally, on April 18, 2005, our board declared a cash distribution for the three months ended March 31, 2005 of $0.42 per unit, or $1.68 per unit annualized, for all outstanding common and subordinated units. The distribution totaling $4.4 million was paid on May 13, 2005 to holders of record at the close of business on May 2, 2005.

        The amount of available cash from operating surplus needed to pay the current distribution of $0.42 per unit, or $1.68 per unit annualized, to our common and subordinated unitholders is as follows (in thousands):

(1)

Includes distributions attributable to restricted units as distributions made on restricted units issued to date are subject to the same vesting provisions as the restricted units. As of March 31, 2005, we had 27,940 outstanding restricted common units, none of which have vested. Annual distributions related to these restricted units are less than $47,000.

Our Indebtedness

CPG Credit Agreement

        CPG and certain of Copano Pipelines' operating subsidiaries have a $100.0 million revolving credit agreement, which matures on February 12, 2008. As of March 31, 2005, $45.0 million was outstanding under this revolving credit facility, bearing interest at a weighted average interest rate of 5.9%. Please read Note 4 to the unaudited consolidated financial statements for additional information about the CPG Credit Agreement.

CHC Facility

        In November 2004, concurrently with the closing of our Offering, CHC and the Copano Processing operating subsidiaries established a $12.0 million revolving credit facility. As of March 31, 2005, $8.0 million was outstanding under this revolving credit facility, bearing interest at a weighted average interest rate of 5.3%. Please read Note 4 to the unaudited consolidated financial statements for additional information about the CHC Facility.

Recent Accounting Pronouncements

        For information on new accounting pronouncements, please read Note 2 to the unaudited consolidated financial statements.

Critical Accounting Policies

        For a discussion of our critical accounting policies, which are related to revenue recognition, depreciation, amortization and impairment of long-lived assets and financial instruments previously classified as equity and are now classified as liabilities and equity method of accounting, and which remain unchanged, please read "Management's Discussion and Analysis of Financial Condition and Results of

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Operation—Significant Accounting Policies and Estimates" in our Annual report on Form 10-K for the year ended December 31, 2004.

Non-GAAP Financial Measures

        The following table presents a reconciliation of the non-GAAP financial measures of (1) total gross margin (which consists of the sum of individual segment gross margins) to operating income and (2) EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities for each of the periods indicated (in thousands).

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

        Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk for natural gas and NGLs. We also incur, to a lesser extent, risks related to interest rate fluctuations. We do not engage in commodity energy trading activities.

        Interest Rate Risk.    We are exposed to changes in interest rates as a result of our revolving credit facilities, which had an average floating interest rate of 5.8% as of March 31, 2005. We had a total of $53.0 million of indebtedness outstanding under our credit facilities as of March 31, 2005. The impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.5 million annually.

        Commodity Price Risks.    Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. The current mix of our contractual

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arrangements, together with our ability to condition natural gas during periods of unfavorable processing margins, significantly reduces our exposure to natural gas and NGL price volatility. Natural gas prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services. For the three months ended March 31, 2005, the impact on our gross margin of a $0.01 per gallon change (increase or decrease) in NGL prices would result in a corresponding change of $0.6 million to our gross margin and the impact on our gross margin of a $0.10 per MMBtu increase (decrease) in the price of natural gas would result in a decrease (increase) of $0.5 million to our gross margin. Increases in natural gas prices or reduced natural gas liquids prices could trigger favorable provisions under our restructured processing agreement, which is expected to reduce our exposure to adverse processing margins. If processing margins are negative, we can operate the plant in a conditioning mode such that additional price increases in natural gas would have an anticipated positive impact to our gross margin.

        Credit Risk.    We are diligent in attempting to ensure that we provide credit to only credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability.

Item 4. Controls and Procedures.

        We carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on the valuation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports files or submitted under the Exchange Act is recorded, processed, summarized and reported timely.

        There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2005 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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PART II-OTHER INFORMATION

Item 1. Legal Proceedings.

        We are named as a defendant, from time to time, in litigation relating to our normal business operations. Our management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

Item 6. Exhibits.

        Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

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