Copano Energy, L.L.C. - 10-Q Quarterly Report

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

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

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

There were 7,038,252 common units of Copano Energy, L.L.C. outstanding at December 20, 2004. Copano Energy, L.L.C.'s common units trade on The Nasdaq National Market under the symbol "CPNO."

		Page
Item 1.	Financial Statements.	3
	Unaudited Consolidated Balance Sheets—September 30, 2004 and December 31, 2003	3
	Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2003	4
	Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2004 and 2003	5
	Unaudited Consolidated Statement of Members' Capital for the Nine Months Ended September 30, 2004	6
	Notes to Unaudited Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 6.	Exhibits and Reports on Form 8-K.	39

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS' CAPITAL
(Unaudited)

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

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 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 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 (other than from the underwriters' exercise of their over-allotment option) were used (i) to redeem CE's redeemable preferred units from pre-Offering investors for $78,077,000 (see Note 5), (ii) to reduce existing indebtedness under the CPG Credit Agreement by $6,000,000, (iii) to reduce existing indebtedness under the Tejas Credit Agreement by $7,000,000 (see Note 4), (iv) to pay other obligations of $957,000 and (v) to pay expenses of the Offering. The Company used net proceeds from the exercise of the underwriters' over-allotment option to redeem common units, on a pro rata basis, from certain investors existing prior to the Offering. After this redemption of common units, pre-Offering investors own 1,288,252 common units and 3,519,126 subordinated units and the public owns 5,750,000 common units (see Note 6).

Concurrent with the closing of the Offering, Copano Houston Central, L.L.C. ("CHC"), a Delaware limited liability company and a wholly owned subsidiary of CE, entered into a new $12 million secured revolving credit facility. At the closing, CHC borrowed $9,000,000 under this facility to retire the remaining balance outstanding under the Tejas Credit Agreement (see Note 4). Additionally, concurrent with the closing of the Offering, Copano Pipelines Group, L.L.C. ("CPG"), a Delaware limited liability company and a wholly owned subsidiary of CE, amended its existing $100 million secured revolving credit facility (see Note 4).

See Note 12 for unaudited pro forma financial information, which gives effect to the Offering and related transactions as if the Offering and related transactions had occurred on September 30, 2004.

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 ("SEC"). 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 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 Form S-1 Registration Statement (No. 333-117825) as filed with the SEC on November 3, 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, 2003, CGP had a net operating loss carryforward of approximately $621,000, 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.

In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities—An Interpretation of Accounting Research Bulletin 51." FIN 46 addresses consolidation by business enterprises of variable interest entities ("VIEs") and provides guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a variable interest (or combination of variable interests) that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. The Company adopted FIN 46 as of December 31, 2003.

In August 2004, the Company acquired a gathering system located in northern Bee and southern Karnes Counties, Texas, for $276,000.

			September 30, 2004			December 31, 2003
Current portion of long-term debt:
	CHC Credit Agreement		$	—		$	7,800

Long-term debt:
	CPG Credit Agreement			54,000			27,500
	Tejas Credit Agreement:
		Senior debt outstanding		16,013			—
		Discount		(341	)		—

		Total	$	69,672		$	27,500

Subordinated Debt:
	Tejas Credit Agreement		$	—		$	30,398

In connection with the Offering discussed in Note 1, the Company used proceeds from the Offering to partially repay its existing long-term indebtedness under the CPG Credit Agreement and, together with borrowings under the new CHC Facility, to retire the balance outstanding under the Tejas Credit Agreement.

During the first quarter of 2004, CPG and certain Copano Pipelines operating subsidiaries amended and restated their revolving credit agreement (the "CPG Credit Agreement") with a syndicate of commercial banks to, among other things, increase the lenders' commitment amount to $100 million and extend maturity of the facility to February 12, 2008. In connection with the closing of the Offering, on November 15, 2004, the CPG Credit Agreement was amended to, among other things, modify certain financial covenants to permit CPG to make cash distributions to CE to the extent of "available cash" (as defined in the CPG Credit Agreement). Additional borrowings under the CPG Agreement in February 2004 were used primarily by CPG to acquire a pipeline operating subsidiary from CHC, which in turn used the proceeds to pay in full $7,800,000 outstanding under the CHC Credit Agreement discussed below and to reduce the outstanding balance under the Tejas Credit Agreement, discussed below, by $15,199,000. The balance outstanding under the CPG Credit Agreement totaled $54,000,000 as of September 30, 2004 and was reduced to $48,000,000 using proceeds from the Offering in November 2004. Future borrowings under this facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The CPG Credit Agreement 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, as amended, including certain financial covenants.

The obligations under the CPG Credit Agreement are secured by first priority liens on substantially all of the assets of CPG and its subsidiaries (other than certain subsidiaries with insignificant assets) and CE's interest in CPG. Additionally, the obligations under the CPG Credit Agreement are guaranteed by CE and CPG and its subsidiaries (other than certain subsidiaries with insignificant assets).

The CPG Credit Agreement contains various covenants that limit CPG and certain Copano Pipelines operating subsidiaries' ability to grant certain liens; make certain loans, acquisitions, capital expenditures and investments; make distributions other than from available cash; merge or consolidate unless CPG and certain Copano Pipelines operating subsidiaries are the survivor; or engage in certain asset dispositions, including a sale of all or substantially all of its assets. Additionally, the CPG Credit Agreement limits the ability of CPG and certain Copano Pipelines operating subsidiaries to incur additional indebtedness with certain exceptions, including purchase money indebtedness not to exceed $500,000 to finance the acquisition of assets, indebtedness not to exceed $500,000 incurred in the ordinary course of business and unsecured indebtedness qualifying as subordinated debt. The CPG Credit Agreement also contains covenants, which, among other things, require CPG and certain Copano Pipelines operating subsidiaries to maintain specified ratios or conditions as follows:

Based upon the senior debt to EBITDA ratio calculated as of September 30, 2004 (utilizing trailing four quarters' EBITDA), CPG had approximately $7,450,000 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 September 30, 2004. 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.

In November 2001, CHC and its then subsidiaries entered into a $35 million credit agreement (the "CHC Credit Agreement") with a syndicate of commercial banks. In February 2004, this credit facility was paid in full and terminated using proceeds from the conveyance of a pipeline operating subsidiary to CPG discussed above. In February 2004, effective with the early termination of the CHC Credit Agreement, the Company charged $314,000 to interest expense, representing the balance of the unamortized debt issue costs.

Concurrent with the closing of the Offering, on November 15, 2004, CHC and certain of its subsidiaries entered into a $12 million secured revolving credit facility (the "CHC Facility") with Comerica Bank. At the closing, CHC borrowed $9,000,000 under this facility to retire the remaining balance outstanding under the Tejas Credit Agreement discussed below. CHC expects to use the remaining amount of this credit facility to finance capital expenditures (including construction and expansion projects) as well as meet working capital requirements of its processing operations.

The obligations under this revolving credit facility are secured by first priority liens on substantially all of the assets of CHC and its subsidiaries and CE's interest in CHC. Additionally, CHC and certain of its subsidiaries are jointly and severally liable as borrowers under this revolving credit facility, and the obligations under the revolving credit facility are guaranteed by CE and CHC and its subsidiaries that are not borrowers under this facility.

The CHC Facility contains various covenants that limit the ability of CHC and its subsidiaries to incur indebtedness (excluding current accounts payable arising in the normal course of business and purchase money indebtedness not to exceed $500,000 for any fiscal year); grant certain liens; make certain loans, acquisitions and investments; make distributions if a default or event of default exists; change its capital structure; merge or consolidate; or sell all or any material part of its assets. Additionally, the CHC Facility contains covenants, which, among other things, require CHC and its subsidiaries to maintain specified ratios or conditions as follows:

Management believes that CHC and its subsidiaries are in compliance with the covenants under the CHC Facility. 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.

In 2001, CHC and its then subsidiaries and Tejas Energy NS, LLC ("Tejas") entered into a subordinated credit agreement (the "Tejas Credit Agreement") which provided for a $21.2 million original subordinated term loan. In connection with the Tejas Credit Agreement, CHC issued a warrant to Tejas (the "Tejas Warrant"), which provided Tejas the right to acquire up to 10% of the membership interests (100,000 equity membership interests) of CHC. On February 13, 2004, the Company amended and restated the terms of its credit facility with Tejas. In connection with the new credit facility, the exercise price of the Tejas Warrant was repriced at $41.24 per membership interest, or $4,124,000 in the aggregate. CHC had the right to repurchase the warrant for $405,000 by delivering a repurchase notice to Tejas. As a result of this repricing, CHC assigned an allocated value of $395,000 to the warrant issued to Tejas based on the repurchase price of the warrant. The allocated warrant value amount was recorded as a discount against the remaining balance of the amount outstanding under the Tejas Credit Agreement and as an other noncurrent liability. This discount was being accreted as interest expense through August 2008. As of September 30, 2004, the remaining balance of the discount amount totaled $341,000.

The balance of the amount outstanding under the Tejas Credit Agreement of $16,013,000 as of September 30, 2004 was repaid in full on November 15, 2004, concurrent with the completion of the

Offering and the closing of the CHC Facility discussed above. CHC used $9,000,000 borrowed under the CHC Facility and $7,000,000 of Offering proceeds to retire the debt outstanding under the Tejas Agreement. CHC used cash on hand to repurchase the Tejas Warrant for $405,000. As a result of purchasing the Tejas Warrant, the Company will record additional interest expense of $330,000 in November 2004, which represents the write off of the remaining discount associated with the Tejas Warrant as such redemption is considered an early extinguishment of debt.

Through a series of transactions occurring between August 2001 and November 2001, CE issued redeemable preferred units in consideration for $60,000,000 in cash. The cash proceeds from these issuances were used primarily to fund the asset acquisitions from Tejas, the acquisition of the minority interests in certain predecessor entities and construction costs related to pipeline assets. For the first four years following the initial issuance of the preferred units, CE had the right to pay the quarterly preferred distributions in preferred units at a 10% rate. Except for certain cash distributions during 2002 and 2003, the board elected to pay the preferred distributions in preferred units for all required quarterly distributions, thereby increasing the number of preferred units and aggregate amount outstanding. As of September 30, 2004, preferred units issued and outstanding totaled 758,504 with an aggregate face value of $75,850,000.

Additionally, the preferred unitholders were issued warrants to purchase up to 3,750,000 common units of CE at an exercise price of $16 per unit until August 14, 2011. The Company used the Black-Scholes option pricing model to assign an allocated warrant value of $12,799,000, or $3.41 per warrant, and $47,201,000 to the preferred units. The allocated warrant value amount was recorded as a discount against the redeemable preferred units and as an increase to paid-in capital. This discount is being accreted as additional distributions (interest expense after the adoption of SFAS No. 150 on July 1, 2003) through the mandatory redemption date. As of September 30, 2004, the remaining balance of the discount amount totaled $8,158,000.

Prior to the closing of the Offering in November 2004, the preferred unitholders exchanged these warrants for 1,211,120 common units and 2,091,048 subordinated units (as described in Note 7) of CE based upon the exercise price of the warrants and the value of the underlying common units issued to the public. In addition, net proceeds from the Offering were used to redeem all outstanding redeemable preferred units for $78,077,000. As a result of this redemption, the Company will record additional interest expense of $7,946,000 in November 2004, which represents the write off of the remaining discount associated with the redeemable preferred units as such redemption is considered an early extinguishment of debt. Additionally, as a result of this redemption, CE will write off the unamortized balance of issuance costs associated with the redeemable preferred units of $921,000 (balance of this unamortized portion of debt issue costs totaled $951,000 as of September 30, 2004).

On August 14, 2001, 5,000,000 common units and 620,000 junior units of CE were designated. In transactions occurring on August 14, 2001 and November 27, 2001, Copano Partners, L.P., an entity controlled by John R. Eckel, Jr., Chairman of the Board and Chief Executive Officer of the Company,

contributed general and limited partnership interests in certain predecessor entities and operating subsidiaries to CE in exchange for 1,030,000 common units and 620,000 junior units of CE.

Effective January 2002, 212,000 nonvoting special units of CE were designated, 154,000 of which were designated as common special units and 58,000 of which were designated as junior special units. The initial purchase of the 72,000 special units issued effective January 2002 to an executive officer was financed by a subscription receivable. The second purchase of the 140,000 special units issued effective April 1, 2003 to another executive officer was financed by a subscription receivable, one third of which was forgiven on April 1, 2004. On July 30, 2004, Copano/Operations, Inc. ("Copano Operations"), an entity controlled by Mr. Eckel and which provides management, operations and administrative support services to the Company, loaned these two executive officers a total of $143,000. These officers used the loan proceeds to pay CE for the balance of the acquisition price for the special units (subscription receivable).

On November 15, 2004, immediately prior to the completion of the Offering, (i) Copano Partners exchanged its common units and junior units for 763,221 common units and 1,317,733 subordinated units representing approximately 19.71% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters' over-allotment option and (ii) two executive officers exchanged their common special units and junior special units for an aggregate of 63,911 common units and 110,345 subordinated units representing approximately 1.65% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters' over-allotment option. Additionally as discussed in Note 5, on November 15, 2004, immediately prior to the completion of the Offering, the preferred unitholders exchanged their warrants for an aggregate of 1,211,120 common units and 2,091,048 subordinated units. After redemption of certain common units received by the preferred unitholders using proceeds from the underwriters' exercise of the over-allotment option, the former preferred unitholders hold an aggregate of 461,120 common units and 2,091,048 subordinated units representing approximately 24.18% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters' over-allotment option.

On November 15, 2004, CE completed the Offering by issuing 5,750,000 common units at $20.00 per common unit representing 54.46% of the outstanding units of CE. As of September 30, 2004, expenses of the Offering totaled $3,433,000 and are included in other assets on the consolidated balance sheet. Expenses of the Offering (including underwriting discounts and commissions) are expected to total approximately $13.1 million. After the redemption of certain common units using net proceeds from the underwriters' over-allotment option, pre-Offering investors own an aggregate of 1,288,252 common units and the public owns an aggregate of 5,750,000 common units.

Subordinated units represent limited liability interests in CE, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. All 3,519,126 subordinated units outstanding after the Offering are held by pre-Offering investors and represent approximately 33.33% of total units outstanding after the Offering. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.40 per unit for each quarter since

the commencement of operations. Subordinated units will convert into common units on an one-for-one basis when the subordination period ends. Pursuant to CE's limited liability company agreement, the subordination period will extend until the first day of any quarter beginning after December 31, 2006 that each of the following financial tests is met: (1) distributions of "available cash from operating surplus" (as defined) on each of the outstanding common units and subordinated units for the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the minimum quarterly distribution; (2) the "adjusted operating surplus" (as defined) generated during the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all outstanding common units and subordinated units; and (3) there are no arrearages in payment of the minimum quarterly distributions on the common units.

On November 15, 2004, CE granted employees, excluding Mr. Eckel, a total of 200,000 unit options to purchase an equal number of common units at $20.00 per unit. 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.

On December 13, 2004, CE awarded 3,000 restricted common units to each of its six independent directors, for a total of 18,000 units. Each restricted unit grant vests in equal one-third annual installments commencing on the first anniversary of the grant date or upon a change of control, death, disability or, in certain circumstances, retirement.

On July 30, 2004, CE made a distribution totaling $143,000 to two executive officers, which they used to retire the obligations outstanding under their loans with Copano Operations (discussed above).

On November 15, 2004, after the exchange of existing warrants, common units, common special units, junior units and junior special units for new common units and subordinated units and prior to the completion of the Offering to the public, CE made a special distribution to pre-Offering unitholders totaling $4,000,000, which the pre-Offering unitholders placed in an escrow account. These escrowed funds will be available to fund general and administrative expenses in excess of limits established in the limited liability company agreement, if any.

The holders of the common and subordinated units are entitled to participate in distributions. The common units will 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 will not accrue distribution arrearages. After the expiration of the subordination period, common units will no longer be entitled to arrearages.

Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of units outstanding during the period. Dilutive net income (loss) per unit reflects potential dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of 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 unit is calculated as follows (in thousands, except per unit amounts):

			Three Months Ended September 30,					Nine Months Ended September 30,
			2004		2003			2004		2003
Net income (loss)			$	2,703	$	(3,574	)	$	1,491	$	(3,430	)
Cash distributions to preferred unitholders				—		—			—		(810	)

Net income (loss) available—basic			$	2,703	$	(3,574	)	$	1,491	$	(4,240	)

Net income (loss) allocable to each class—basic
	Common units		$	2,352	$	(3,109	)	$	1,297	$	(3,794	)
	Common special units			351		(465	)		194		(446	)

		Total	$	2,703	$	(3,574	)	$	1,491	$	(4,240	)

Basic weighted average units:
	Common units			1,030		1,030			1,030		1,030
	Common special units			154		154			154		121
Basic net income (loss) per unit:
	Common units		$	2.28	$	(3.02	)	$	1.26	$	(3.68	)
	Common special units		$	2.28	$	(3.02	)	$	1.26	$	(3.68	)

Diluted net income (loss) per unit is calculated as follows (in thousands, except per unit amounts):

			Three Months Ended September 30,					Nine Months Ended September 30,
			2004		2003			2004		2003
Net income (loss)			$	2,703	$	(3,574	)	$	1,491	$	(3,430	)
Accretion of preferred units				426		—			—		—
Cash distributions to preferred unitholders				—		—			—		(810	)
Payment-in-kind distributions to preferred unitholders				1,525		—			—		—

Net income (loss) available—dilutive			$	4,654	$	(3,574	)	$	1,491	$	(4,240	)

Net income (loss) allocable to each class—dilutive
	Common units		$	4,509	$	(3,109	)	$	1,297	$	(3,794	)
	Common special units			145		(465	)		194		(446	)

		Total	$	4,654	$	(3,574	)	$	1,491	$	(4,240	)

Dilutive weighted average units:
	Common units			1,030		1,030			1,030		1,030
	Potential dilutive common units			3,750		—			—		—

				4,780		1,030			1,030		1,030

	Common special units			154		154			154		121

Dilutive net income (loss) per unit:
	Common units		$	0.94	$	(3.02	)	$	1.26	$	(3.68	)
	Common special units		$	0.94	$	(3.02	)	$	1.26	$	(3.68	)

As of September 30, 2004, CE had 3,750,000 potentially dilutive warrants outstanding and CHC had a potentially dilutive warrant, the Tejas Warrant (see Note 4), outstanding for all periods presented. For the three and nine months ended September 30, 2003, all of these potentially dilutive warrants were not included in dilutive income (loss) per unit because to do so would have been anti-dilutive. For the three and nine months ended September 30, 2004, the Tejas Warrant was not included in dilutive income (loss) per unit because to do so would have been anti-dilutive. For the nine months ended September 30, 2004, the CE warrants were not included because to do so would have been anti-dilutive.

Net income (loss) per unit has not been presented for junior units and junior special units as such units were not entitled to share in earnings for the periods presented.

The Company does not directly employ any persons to manage or operate its business. With respect to the Texas operating subsidiaries of the Company, Copano Operations provides these services. The Company reimburses Copano Operations for all direct and indirect costs of these services, which include management, operations and administrative support services. Copano Operations charges 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 performs services. Management believes that this methodology is reasonable. For the three months ended September 30, 2004 and 2003, the Company reimbursed Copano Operations $4,426,000 and $2,484,000, respectively, for administrative and operating costs, including payroll and benefits expense for both field and administrative personnel of the Company. For the nine months ended September 30, 2004 and 2003, the Company reimbursed Copano Operations $11,745,000 and $7,306,000, 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 statements of operations. As of September 30, 2004, amounts payable by the Company to Copano Operations were $930,000.

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 and nine month periods ended September 30, 2004 and 2003.

During the three months ended September 30, 2004 and 2003, the Company purchased natural gas and natural gas services from affiliated companies of Mr. Eckel totaling $378,000 and $408,000, respectively, and provided gathering and compression services to affiliated entities of Mr. Eckel totaling $18,000 and $7,000, respectively. During the nine months ended September 30, 2004 and 2003, the Company purchased natural gas and natural gas services from affiliated companies of Mr. Eckel totaling $1,141,000 and $1,627,000, respectively, and provided gathering and compression services to affiliated entities of Mr. Eckel totaling $59,000 and $28,000, respectively. 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 September 30, 2004, amounts payable by the Company to affiliated companies of Mr. Eckel, other than Copano Operations, totaled $173,000.

The Company paid WDG for transportation and purchased natural gas from WDG during 2004 and 2003. Natural gas purchases, net of natural gas sales to WDG, totaled $464,000 and $198,000 for the three months ended September 30, 2004 and 2003, respectively. Natural gas purchases, net of natural gas sales to WDG, totaled $760,000 and $390,000 for the nine months ended September 30, 2004 and 2003, 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 September 30, 2004, the Company's net receivable from WDG totaled $945,000.

For the three months ended September 30, 2004 and 2003, rental expense for office space, leased vehicles and leased compressors and related field equipment used in the Company's operations totaled $334,000 and $468,000, respectively. For the nine months ended September 30, 2004 and 2003, rental

expense for office space, leased vehicles and leased compressors and related field equipment used in the Company's operations totaled $1,307,000 and $1,151,000, respectively.

The Company has both fixed and variable quantity contractual commitments arising in the ordinary course of its natural gas marketing activities. At September 30, 2004, the Company had fixed contractual commitments to purchase 331,700 million British thermal units ("MMBtu") of natural gas in October 2004. At September 30, 2004, the Company had fixed contractual commitments to sell 3,214,700 MMBtu of natural gas in October 2004. All of these contracts are based on index-related market pricing. Using index-related market prices at September 30, 2004, total commitments to purchase natural gas related to such agreements equaled $1,812,000 and the total commitment to sell natural gas under such agreements equaled $16,115,000. 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 September 2004, natural gas volumes purchased under such contracts equaled 4,453,912 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 September 2004, natural gas volumes sold under such contracts equaled 184,133 MMBtu.

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 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 September 30, 2004, the approximate amount of parental guaranteed obligations were as follows (in thousands):

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.

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.

	Nine Months Ended September 30,
	2004		2003
Interest	$	2,556		$	1,464
Taxes		—			—

	Nine Months Ended September 30,
	2004		2003
Increase of redeemable preferred units related to the issuance of payment-in-kind units	—		2,453
Decrease in members' capital related to the issuance of payment-in-kind units	—		(2,453	)
Increase of redeemable preferred units related to the accretion of warrant value	—		743
Decrease in members' capital related to the accretion of warrant value	—		(743	)
Increase members' capital	—		1,258
Decrease redeemable preferred units	—		(1,258	)
(Decrease) increase other comprehensive income (loss)	—		226
Increase (decrease) other current liabilities	—		(226	)
Increase in equity in loss from unconsolidated affiliate	90		90
Decrease in accounts receivable from affiliates	(90	)	(90	)
Decrease in senior debt	(395	)	—
Increase in property, plant and equipment	(381	)	—
Increase in other noncurrent liabilities	776		—

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):

The following table shows unaudited pro forma financial information of the Company giving effect to the Offering and related transactions discussed in Notes 1 (Organization), 4 (Long-Term Debt), 5 (Redeemable Preferred Units) and 6 (Members' Capital and Distributions) as if the Offering and related transactions had occurred on September 30, 2004 (in thousands).

			September 30, 2004
			Historical			Pro Forma
Cash and cash equivalents			$	6,081		$	1,148

Long-term debt and other obligations:
	Long-term debt		$	69,672		$	57,000
	Other noncurrent liabilities			1,689			337

		Total long-term debt and other obligations		71,361			57,337

Redeemable preferred units				67,693			—

Members' capital:
	Common units			—			94,736
	Subordinated units			—			10,470
	Existing unitholders' capital			16,533			—
	Accumulated deficit			(15,664	)		(30,354	)

	Total members' capital			869			74,852

		Total capitalization	$	139,923		$	132,189

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 subsidiaries.

We are a Delaware limited liability company formed in 2001 to acquire entities owning businesses 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 exercised 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 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:

Our results of operations 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 or conditioned and the volume of natural gas 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 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 in part 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 British thermal units, or Btus, that result from processing the natural gas.

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 segment performance. These measurements include the following: (1) throughput volumes and fuel consumption; (2) segment gross margin; (3) operations and maintenance expenses; (4) general and administrative expenses; and (5) EBITDA.

Throughput Volumes and Fuel Consumption. Throughput volumes and fuel consumption 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 minus 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.

In order 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. However, we believe this calculation is representative of our current operating commodity price environment. We use this calculation as an evaluation tool to conduct operations as we are able to isolate the effects of historical and projected commodity price changes on our operations. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices such as volumes, changes in NGL composition, recovery rates and variable contract terms. Our standardized processing margins averaged $0.129 per gallon during the third quarter of 2004 compared to ($0.002) per gallon during the third quarter of 2003. Our standardized processing margins averaged $0.076 per gallon during the nine months ended September 30, 2004 compared to ($0.024) per gallon during the

nine months ended September 30, 2003. The average standardized processing margin for the period from 1989 through September 30, 2004 is $0.0907 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.

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 are incurred through Copano Operations, an affiliate of our company.

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:

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 quarterly limitation on general and administrative expenses will be increased by 10% of the amount by which EBITDA for any quarter exceeds $5.4 million. 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. With respect to the three-year period, the annual general and administrative expense budget requires the approval of a majority of the board prior to the applicable fiscal year and certain changes to this budget require the unanimous approval of board members affiliated with certain of our pre-Offering investors.

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:

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.

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.

Our Processing and Conditioning Economic Model. We utilize a processing and conditioning economic model each business day 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. This model is also used to compare current operating conditions to our standardized processing margin.

Flow and Transaction Monitoring Systems. We recently began utilizing 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 contemplates complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to utilize our 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 may pursue selected acquisitions in new geographic areas, including other areas of Texas, Louisiana 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" beginning on page 32 of this report.

Acquisition Analysis. In analyzing a particular acquisition we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets, strategic fit of the asset in relation to our business strategy, expertise required to manage the asset, capital required to integrate and maintain the asset, and the competitive environment of the area where the assets are located. From a financial perspective, we analyze the rate of return the assets will generate under various case scenarios, comparative market parameters and the additive earnings and cash flow capabilities of the assets.

Capital Expenditure Analysis. We make capital expenditures either to maintain our assets or the supply to our assets or for expansion projects to increase our gross margin. Maintenance capital is employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or is expended 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.

In the latter half of 2003 and the first quarter of 2004, we restructured a number of our contracts, including our contract with Kinder Morgan Texas Pipeline, or KMTP, to provide that at least during periods of relatively low processing margins, we will receive supplemental fees with respect to natural gas that does not meet the downstream transporter's gas quality specifications. These fees provide us additional revenue and compensate us for the conditioning services required to redeliver natural gas that meets downstream pipeline quality specifications. We expect that the restructured contracts, particularly our contract with KMTP, will help reduce the volatility of our processing segment gross margin. In the latter half of 2003, we began to restructure our contractual arrangements with producers and we have realized additional benefits from these efforts in 2004. The full impact of these efforts may affect the comparability of our historical results of operations.

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 "Results of Operations" and "Liquidity and Capital Resources" in Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part I 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:

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 Registration Statement on Form S-1, as amended, filed with the SEC and declared effective November 9, 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.

Pipelines Segment Gross Margin. Pipelines segment gross margin was $7.4 million for the three months ended September 30, 2004 compared to $6.3 million for the three months ended September 30, 2003, an increase of $1.1 million, or 17%. The increase was primarily attributable to higher average natural gas prices during the three months ended September 30, 2004 compared to the three months ended September 30, 2003, which caused an increase in margins associated with our index price-related gas purchase and transportation arrangements. During the third quarter of 2004, the Houston Ship Channel, or HSC, natural gas index price averaged $5.68 per MMBtu compared to $4.95 per MMBtu during the third quarter of 2003, an increase of $0.73, or 15%. Additionally, a portion of this increase was the result of the acquisition of our Karnes County Gathering System in September 2004 and improved contract terms.

Processing Segment Gross Margin. Processing segment gross margin was $7.1 million for the three months ended September 30, 2004, compared to $(0.2) million for the three months ended September 30, 2003, an increase of $7.3 million, or 3,650%. For the three months ended September 30, 2004, we experienced improvements of $9.6 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" beginning on page 23 of this report. As a result of unfavorable commodity prices in the third quarter of 2003, the Houston Central Processing Plant's operations were severely curtailed during certain portions of that period. This increase in processing segment gross margin was partially offset by a reduction in conditioning fee revenue of $1.1 million and processing upgrade payments of $2.3 million to natural gas suppliers and pipeline affiliates during the third quarter of 2004. Our processing segment gross margin was further improved by $1.1 million related to volume gains at the Houston Central Processing Plant during the third quarter of 2004 as compared to the third quarter of 2003.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $3.2 million for the three months ended September 30, 2004 compared with $2.7 million for the three months ended September 30, 2003, an increase of $0.5 million, or 19%. The increase was primarily attributable to: (1) higher repair and maintenance expense totaling $0.5 million in our South Texas ($0.1 million) and Upper Gulf Coast and Coastal Waters Regions ($0.1 million) and at our Houston Central Processing Plant ($0.3 million, of which $0.2 million related to a painting project of certain facilities), (2) increased utility costs at our Houston Central Processing Plant of $0.1 million related to higher plant utilization in 2004 as discussed above offset by (3) lower compression rental expense of $0.1 million in 2004 as a result of our purchase of certain compression equipment in our South Texas Region that had previously been leased.

Depreciation and Amortization. Depreciation and amortization totaled $2.3 million for the three months ended September 30, 2004 compared with $1.5 million for the three months ended September 30, 2003, an increase of $0.8 million, or 53%. This increase relates primarily to additional depreciation and amortization associated with capital expenditures made after September 30, 2003 including the compression equipment purchased earlier this year, the Karnes County Gathering System purchased during the third quarter of 2004 and modifications and enhancements made to the Houston Central Processing Plant during the fourth quarter of 2003. Additionally, this increase includes charges related to pipeline and equipment retirements.

General and Administrative Expenses. General and administrative expenses totaled $2.4 million for the three months ended September 30, 2004 compared with $1.3 million for the three months ended September 30, 2003, an increase of $1.1 million, or 85%. The increase was primarily due to (i) costs of augmented infrastructure and hiring of additional staff incurred in contemplation of becoming a public company of $0.4 million and (ii) certain nonrecurring consulting costs related to restructuring and

acquisition alternatives of $0.5 million and (iii) an increase in our reserve for uncollectible receivables accounted for $0.2 million.

Interest Expense. Interest and other financing costs totaled $3.8 million for each of the three months ended September 30, 2004 and 2003. Interest expense in both periods primarily included interest related to the payment-in-kind units issued to the redeemable preferred unitholders and the accretion of the allocated warrant value associated with the redeemable preferred units. Interest related to these items totaled $2.4 million and $2.1 million for the three months ended September 30, 2004 and 2003, respectively. Additionally, interest expense related to bank facilities and the Tejas Credit Agreement totaled $1.4 million and $1.7 million for the three months ended September 30, 2004 and 2003, respectively. Average borrowings under these facilities were $70.5 million and $68.2 million with average interest rates of 6.9% and 7.7% for the third quarter 2004 and 2003, respectively.

Pipelines Segment Gross Margin. Pipelines segment gross margin was $21.4 million for the nine months ended September 30, 2004 compared to $20.9 million for the nine months ended September 30, 2003, an increase of $0.5 million, or 2%. The increase was primarily attributable to higher average natural gas prices during the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003, which caused an increase in margins associated with our index price-related gas purchase and transportation arrangements. During the first nine months of 2004, the Houston Ship Channel, or HSC, natural gas index price averaged $5.62 per MMBtu compared to $5.51 per MMBtu during the first nine months of 2003, an increase of $0.11, or 2%. Additionally, a portion of this increase was partially offset with milder weather during the winter heating portion of the first quarter of 2004, which resulted in lower volumes being sold to utilities under high-margin arrangements.

Processing Segment Gross Margin. Processing segment gross margin was $12.6 million for the nine months ended September 30, 2004, compared to $0.2 million for the nine months ended September 30, 2003, an increase of $12.4 million, or 6,200%. For the nine months ended September 30, 2004, we experienced improvements of $11.4 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" beginning on page 23 of this report. As a result of unfavorable commodity prices in 2003, the Houston Central Processing Plant's operations were severely curtailed during certain portions of that period. Processing segment gross margin was further improved as a result of increased conditioning fee revenue of $3.1 million for the nine months ended September 30, 2004 compared with the same period in 2003. This increase is attributable to receiving conditioning fee revenues for the full year of 2004 versus a partial year of receiving conditioning fee revenues in 2003. Our processing segment gross margin was also improved by $0.3 million related to volume gains at the Houston Central Processing Plant during the current nine month period as compared to the prior year period. The increased processing segment gross margin was partially offset by an increase in processing upgrade payments of $2.4 million to natural gas suppliers and pipeline affiliates for the nine months ended September 30, 2004 and was the result of increased value of processing in 2004.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $9.2 million for the nine months ended September 30, 2004 compared with $7.7 million for the nine months ended September 30, 2003, an increase of $1.5 million, or 19%. The increase was primarily attributable to: (1) higher repair and maintenance expense totaling $0.8 million in our South Texas ($0.2 million) and Coastal Waters Regions ($0.1 million) and at our Houston Central Processing Plant ($0.5 million, of which $0.2 million related to the painting project of certain facilities and the overhaul of certain engines), (2) increased utility costs at our Houston Central Processing Plant of $0.3 million related to higher plant utilization in 2004 as discussed above, (3) higher compression rental expense of

$0.1 million in 2004 as a result of installing additional compression equipment in our South Texas Region after December 31, 2003, (4) a $0.1 million increase in contract maintenance services costs for our NGL line because in 2004 related reimbursements we received from a third party that shares our right-of-way were lower than reimbursements we received in 2003 and (5) higher environmental, health and safety expenses, measurement costs and performance awards of $0.2 million.

Depreciation and Amortization. Depreciation and amortization totaled $5.5 million for the nine months ended September 30, 2004 compared with $4.5 million for the nine months ended September 30, 2003, an increase of $1.0 million, or 22%. This increase relates primarily to additional depreciation and amortization associated with capital expenditures made after September 30, 2003 including the compression equipment purchased earlier this year, the Karnes County Gathering System purchased during the third quarter of 2004 and modifications and enhancements made to the Houston Central Processing Plant during the fourth quarter of 2003. Additionally, this increase includes charges related to pipeline and equipment retirements.

General and Administrative Expenses. General and administrative expenses totaled $5.9 million for the nine months ended September 30, 2004 compared with $4.0 million for the nine months ended September 30, 2003, an increase of $1.9 million, or 48%. The increase was primarily due to (i) costs of augmented infrastructure and hiring of additional staff incurred in contemplation of becoming a public company of $0.8 million, (ii) an increase in office rent, accounting fees and consulting costs of $0.4 million, (iii) certain nonrecurring consulting costs related to restructuring and acquisition alternatives of $0.5 million and (iv) an increase in our reserve for uncollectible receivables accounted for $0.2 million.

Interest Expense. Interest and other financing costs totaled $11.5 million for the nine months ended September 30, 2004 compared with $7.1 million for the nine months ended September 30, 2003, an increase of $4.4 million, or 62%. Of this increase, $4.6 million was primarily the result of our adoption of SFAS No. 150 on July 1, 2003, which required that the value of the payment-in-kind units issued to the redeemable preferred unitholders be recorded as interest expense, whereas before the adoption of SFAS 150, this value was recorded as an increase to accumulated deficit. Similarly, the accretion of the allocated warrant value associated with the redeemable preferred units was also recorded as interest expense beginning July 1, 2003. This increase was partially offset by lower interest expense related to our credit facilities as a result of lower bank debt outstanding during the period and lower interest rates on the outstanding borrowings.

Our pipeline margins are dependent on the price of natural gas in our operating region. Increases in natural gas prices have a positive impact on our pipeline margins and conversely, a reduction in natural gas prices negatively impacts our pipeline margins. On average, natural gas prices for the last half of 2004 have trended upward and 2004 natural gas prices were higher than those in the first half of 2004 and for full-year 2003. Volumes of natural gas on our pipelines also impact our pipeline margins. Increases in volumes gathered or transported positively impact our pipeline margins. Conversely, reductions in gathered or transported volumes negatively impact our pipeline margins. Our objective is to maintain or increase the volume of natural gas that flows through our pipeline systems or to increase the margin received for the gas that is gathered or transported on these systems. Higher natural gas prices typically increase the amount of drilling activity in our operating regions. We believe that natural gas prices will continue to fluctuate over the next twelve months.

We expect our standardized processing margins to continue to fluctuate over the next 12 months but to remain higher than 2003 levels based on our 2004 year to date experience. Standardized processing margins for the second half of 2004 are expected to be higher than historical average

margins based on calculations we have performed using natural gas and natural gas liquids prices for the period from 1989 through September 30, 2004.

Cash generated from operations, borrowings under our credit facility and funds from private and future public 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.

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:

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 on deciding whether to pursue a particular acquisition, please read "—Our Growth Strategy—Acquisition Analysis" beginning on page 25 of this report.

During the three months ended September 30, 2004, our capital expenditures totaled $2.4 million, consisting of $2.3 million of expansion capital and $0.1 million of maintenance capital. During the nine months ended September 30, 2004, our capital expenditures totaled $6.5 million, consisting of $5.3 million of expansion capital and $1.2 million of maintenance capital. The majority of the expansion capital expenditures relate to the purchase of compressor units that we previously leased and the acquisition of our Karnes County Gathering System, which is a 15-mile pipeline operating in the northern Bee and southern Karnes Counties, Texas as well as the continued development of our SCADA system. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our credit facilities and the issuance of additional equity as appropriate given market conditions and anticipate expending between $3.0 million and $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 September 30, 2004 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 September 30, 2004, we had fixed contractual commitments to purchase 3,214,700 MMBtu of natural gas in October 2004. All of these contracts were based on index-related prices. Using these index-related prices at September 30, 2004, we had total commitments to purchase $1.8 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 September 2004, we purchased 4,453,912 MMBtu of natural gas under such contracts.

Cash Flows. The following summarizes our cash flows for the nine months ended September 30, 2004 and 2003.

	Nine Months Ended September 30,
	2004			2003
Net cash provided by operating activities	$	7,706		$	11,629
Net cash used in investing activities		(6,524	)		(4,670	)
Net cash provided by (used in) financing activities		292			(3,154	)

Net increase in cash and cash equivalents		1,474			3,805
Cash and cash equivalents at beginning of period		4,607			5,136

Cash and cash equivalents at end of period	$	6,081		$	8,941

Operating: For the nine months ended September 30, 2004, operating cash flows of $7.7 million reflect net income of $1.5 million and the following non-cash items: depreciation and amortization of $6.4 million, payment-in-kind interest on redeemable preferred units of $5.5 million, accretion of preferred unitholders warrant value of $1.2 million, payment-in-kind interest and accretion related to subordinated debt of $0.9 million, equity earnings of unconsolidated affiliate of $(0.3) million, and working capital increases of $7.5 million.

For the nine months ended September 30, 2003, operating cash flows of $11.6 million reflect a net loss of $3.4 million and the following non-cash items: depreciation and amortization of $5.4 million, payment-in-kind interest on subordinated debt of $2.9 million, payment-in-kind interest on redeemable preferred units of $1.7 million, accretion of preferred unitholders warrant value of $0.4 million, equity loss of unconsolidated affiliate of $0.5 million and working capital reductions of $4.1 million.

The overall decrease of $3.9 million in operating cash flow from the nine months ended September 30, 2004 to the nine months ended September 30, 2003 was primarily the result of an increase in net income and non-cash items itemized above of $7.7 million and a decrease in the changes in working capital components (exclusive of cash and cash equivalents) of $11.6 million. This decrease in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of decreased accounts payable as a result of the resolution of a dispute between a royalty owner and an operator from which we purchase natural gas. As a result of the dispute, we had suspended payments to the operator. Upon receiving notice that the parties had substantially resolved their dispute, we used additional cash during the second quarter of 2004 when we released approximately $6.1 million in suspended funds to pay the operator for natural gas we had purchased during 2002, 2003 and early 2004.

Investing: Net cash used in investing activities was $6.5 million for the nine months ended September 30, 2004 and $4.7 million for the nine months ended September 30, 2003. Capital expenditures for 2004 include costs for the acquisition of compression equipment and the Karnes County Gathering System as well as the continued development of our SCADA system. Capital expenditures in 2003 include expenditures for the modification to our Houston Central Processing Plant to increase the plant's conditioning capabilities and the development of our SCADA system.

Financing: Net cash provided by (used in) financing activities was $0.3 million for the nine months ended September 30, 2004 and $(3.2) million for the nine months ended September 30, 2003. Cash provided by financing activities for the nine months ended September 30, 2004 primarily includes net borrowings of long-term debt of approximately $4.5 million offset by deferring Offering costs of $2.6 million and deferred financing costs of $1.6 million. For the nine months ended September 30, 2003, cash used in financing activities was primarily attributable to our net repayment of $1.9 million in long-term debt, distributions to the holders of the redeemable preferred units of $0.8 million, deferred financing costs of $0.3 million and deferring Offering costs of $0.2 million.

Cash Distributions and Reserves: Except with respect to the fourth quarter of 2004, we intend to pay each quarter in arrears (in February, May, August and November of each year), to the extent we have sufficient available cash from operating surplus, the minimum quarterly distributions of $0.40 per unit (or $1.60 per year), to our common and subordinated unitholders. For the fourth quarter of 2004, we intend to make an adjusted distribution in February 2005 to reflect the closing of the Offering on November 15, 2004. Available cash for any quarter will consist generally of all cash on hand at the end of that quarter, plus working capital borrowings after the end of the quarter, as adjusted for reserves. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus working capital borrowings after the end of the quarter, plus $12.0 million, as adjusted for reserves. Our limited liability agreement currently prohibits us from borrowing under our credit facilities to pay distributions of operating surplus to unitholders because no such borrowings would constitute eligible "working capital borrowings" pursuant to the definition contained in our limited liability company agreement. The amount of available cash from operating surplus needed to pay the minimum quarterly distribution our unitholders is as follows (in thousands):

CPG and certain Copano Pipelines operating subsidiaries have a $100.0 million revolving credit agreement, which matures on February 12, 2008. As of September 30, 2004, $54.0 million was outstanding under this revolving credit facility, bearing interest at a weighted average interest rate of 4.783%. We used $6.0 million of the proceeds from the Offering in November 2004 to reduce the amount outstanding under this facility to $48.0 million.

Future borrowings under this revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes; however, our limited liability agreement currently prohibits us from borrowing under this credit facility to pay distributions of operating surplus to unitholders because no such borrowings would constitute eligible "working capital borrowings" pursuant to the definition contained in our limited liability company agreement. This 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, as amended, including certain financial covenants (see Note 4 to the consolidated financial statements). Based upon the senior debt to EBITDA ratio calculated as of September 30, 2004 (utilizing trailing for quarters' EBITDA), CPG had approximately $7.4 million of unused capacity under the CPG Credit Agreement. However, as of December 17, 2004, as a result of using Offering proceeds to reduce the balance outstanding under the CPG Credit Agreement, CPG has approximately $13.4 million of unused capacity.

At CPG's election, interest under this revolving credit facility is determined by reference to (1) the reserve-adjusted London interbank offered rate, or LIBOR, plus an applicable margin between 1.75% and 3% per annum or (2) the prime rate plus, in certain circumstances, an applicable margin between 0.25% and 1.5% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.

Our management believes that CPG and its subsidiaries are in compliance with the terms of the CPG Credit Agreement as of September 30, 2004. 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.

Historically, we have financed our processing operations through a $35 million revolving credit facility, which was repaid in February 2004, as well as through a $21.2 million term loan entered into in August 2001 (discussed in Note 4 to the consolidated financial statements). The term loan would have matured on August 14, 2008 and bore interest at a rate of 14%. As of September 30, 2004, approximately $16.0 million remained outstanding under this term loan, and in November 2004, we used $7.0 million from the Offering to reduce this balance.

In November 2004, concurrently with the closing of the Offering, we established a $12.0 million revolving credit facility, the CHC Facility, which we will use to finance capital expenditures (including construction and expansion projects) as well as to meet working capital requirements of our processing operations. Approximately $9.0 million was drawn under this facility concurrently with the closing of the Offering to retire in full the term loan and we believe that an additional $3.0 million is available to be drawn.

At CHC's election, interest under the new revolving credit facility will be determined by reference to (1) the reserve-adjusted interbank offered rate, or IBOR, plus an applicable margin between 2.5% and 3.5% per annum or (2) the prime rate plus, in certain circumstances, an applicable margin of up to 1.5% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date

for IBOR loans, except that if the interest period for an IBOR loan is six months, interest will be paid at the end of each three-month period. For additional information regarding restrictions and covenants under this credit agreement, please read Note 4 to the consolidated financial statements.

Our limited liability agreement currently prohibits us from borrowing under this credit facility to pay distributions of operating surplus to unitholders because no such borrowings would constitute eligible "working capital borrowings" pursuant to the definition contained in our limited liability company agreement.

Our management believes that CHC and its subsidiaries are in compliance with the covenants under this facility. 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. Please read Note 4 to the consolidated financial statements for additional information about the CHC Facility.

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

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, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Significant Accounting Policies and Estimates" in our Form S-1 Registration Statement (No. 333-117825) as filed with the SEC on November 3, 2004.

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 and cash flows from operating activities for each of the periods indicated (in thousands).

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 facility, which had a floating interest rate as of September 30, 2004. We had a total of $54.0 million of indebtedness outstanding under our credit facility at September 30, 2004. 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 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 nine months ended September 30, 2004, the impact on our gross margin of a $0.01 per gallon change (increase or decrease) in NGL prices would result in a change (increase or decrease) of $1.7 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 $1.4 million to our gross margin.

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 as of September 30, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

There have been no changes in our internal controls over financial reporting that occurred during the three or nine months ended September 30, 2004 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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.

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).
3.4		Administrative and Operating Services Agreement dated November 15, 2004, among Copano/Operations, Inc. and Copano Energy, L.L.C., and the Copano Operating Subsidiaries listed therein (incorporated by reference to Exhibit 3.4 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).
10.1		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).

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the December 20, 2004.

ý	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2004
OR
o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Delaware (State or Other Jurisdiction of Incorporation or Organization)		51-0411678 (I.R.S. Employer Identification Number)
2727 Allen Parkway, Suite 1200 Houston, Texas 77019 (Address of Principal Executive Offices)
(713) 621-9547 (Registrant's Telephone Number, Including Area Code)

			September 30, 2004			December 31, 2003
			(In thousands, except unit information)
ASSETS
Current assets:
	Cash and cash equivalents		$	6,081		$	4,607
	Escrow cash			—			1,001
	Accounts receivable, net			32,185			25,605
	Accounts receivable from affiliates			945			651
	Prepayments and other current assets			1,179			1,035

		Total current assets		40,390			32,899

Property, plant and equipment, net				118,630			117,032

Intangible assets, net				4,356			4,397
Investment in unconsolidated affiliate				4,245			4,072
Other assets, net				6,423			3,309

		Total assets	$	174,044		$	161,709

LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
	Accounts payable		$	29,631		$	31,369
	Accounts payable to affiliates			1,103			1,371
	Current portion of long-term debt			—			7,800
	Other current liabilities			3,387			1,960

		Total current liabilities		34,121			42,500

Long-term debt, net of current portion				69,672			27,500
Subordinated debt				—			30,398
Other noncurrent liabilities				1,689			991
Redeemable preferred units ($100 face value, 1,000,000 units authorized, 703,870 units and 758,504 units issued and outstanding as of December 31, 2003 and September 30, 2004, respectively)				67,693			60,982
Commitments and contingencies (Note 9)
Members' capital:
	Common units, no par value, 5,000,000 units authorized, 1,030,000 units issued and outstanding			3,471			3,471
	Common special units, no par value, 154,000 units outstanding			154			154
	Junior units, no par value, 620,000 units authorized, issued and outstanding			526			526
	Junior special units, no par value, 58,000 units outstanding			29			29
	Paid-in capital			12,353			12,353
	Accumulated deficit			(15,664	)		(17,012	)
	Subscription receivable			—			(183	)

				869			(662	)

		Total liabilities and members' capital	$	174,044		$	161,709

			Three Months Ended September 30,						Nine Months Ended September 30,
			2004			2003			2004			2003
			(In thousands)
Revenue:
	Natural gas sales		$	72,524		$	79,471		$	195,788		$	250,552
	Natural gas sales—affiliates			73			—			503			10
	Natural gas liquids sales			45,436			11,126			112,703			38,291
	Transportation, compression and processing fees			2,285			2,180			7,036			5,610
	Transportation, compression and processing fees—affiliates			18			7			59			28
	Other			459			147			1,226			821

		Total revenue		120,795			92,931			317,315			295,312

Costs and expenses:
	Cost of natural gas and natural gas liquids			104,905			85,767			279,707			270,223
	Cost of natural gas and natural gas liquids—affiliates			790			563			2,078			1,906
	Transportation			516			434			1,199			1,988
	Transportation—affiliates			125			43			326			121
	Operations and maintenance			3,186			2,695			9,155			7,672
	Depreciation and amortization			2,252			1,538			5,498			4,528
	General and administrative			2,387			1,316			5,884			3,962
	Taxes other than income			247			236			748			715
	Equity in (earnings) loss from unconsolidated affiliate			(96	)		109			(263	)		558

		Total costs and expenses		114,312			92,701			304,332			291,673

Operating income				6,483			230			12,983			3,639
Other income (expense):
	Interest and other income			25			11			47			34
	Interest and other financing costs			(3,805	)		(3,815	)		(11,539	)		(7,103	)

Net income (loss)			$	2,703		$	(3,574	)	$	1,491		$	(3,430	)

Basic net income (loss) per unit:
	Common units		$	2.28		$	(3.02	)	$	1.26		$	(3.68	)
	Common special units		$	2.28		$	(3.02	)	$	1.26		$	(3.68	)
Basic weighted average number of units:
	Common units			1,030			1,030			1,030			1,030
	Common special units			154			154			154			121
Diluted net income (loss) per unit:
	Common units		$	0.94		$	(3.02	)	$	1.26		$	(3.68	)
	Common special units		$	0.94		$	(3.02	)	$	1.26		$	(3.68	)
Diluted weighted average number of units:
	Common units			4,780			1,030			1,030			1,030
	Common special units			154			154			154			121

					Nine Months Ended September 30,
					2004			2003
					(In thousands)
Cash Flows From Operating Activities:
	Net income (loss)				$	1,491		$	(3,430	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation and amortization				5,498			4,528
		Amortization of debt issue costs				912			847
		Equity in loss (earnings) from unconsolidated affiliate				(263	)		558
		Payment-in-kind interest on subordinated debt				814			2,872
		Payment-in-kind interest to preferred unitholders				5,464			1,701
		Accretion of preferred unitholders warrant value				1,247			385
		Accretion of subsidiary warrant value				54			—
		(Increase) decrease in:
			Accounts receivable			(6,579	)		(1,695	)
			Accounts receivable from affiliates			(204	)		(340	)
			Prepayments and other current assets			(144	)		1,013
		Increase (decrease) in:
			Accounts payable			(1,738	)		6,645
			Accounts payable to affiliates			(268	)		(716	)
			Other current liabilities			1,427			(739	)
			Other			(5	)		—

				Net cash provided by operating activities		7,706			11,629

Cash Flows From Investing Activities:
	Additions to property, plant and equipment and intangible assets					(6,248	)		(4,646	)
	Acquisitions of property, plant and equipment					(276	)		—
	Investment in unconsolidated affiliate					—			(24	)

	Net cash used in investing activities					(6,524	)		(4,670	)

Cash Flows From Financing Activities:
Repayments of long-term debt						(12,300	)		(11,700	)
	Proceeds from long-term debt					31,000			9,850
	Escrow cash					1,001			—
	Repayment of subordinated debt					(15,199	)		—
	Repayments of other long-term obligations					(34	)		(14	)
	Deferred financing costs					(1,541	)		(347	)
	Payment of subscription receivable					143			—
	Distributions to special unitholders					(143	)		—
	Distributions to preferred unitholders					—			(810	)
	Deferred offering costs					(2,635	)		(133	)

	Net cash provided by (used in) financing activities					292			(3,154	)

Net increase in cash and cash equivalents						1,474			3,805
Cash and cash equivalents, beginning of period						4,607			5,136

Cash and cash equivalents, end of period					$	6,081		$	8,941

	Common			Common Special			Junior			Junior Special
	Number of Units	Common Units		Number of Units	Common Special Units		Number of Units	Junior Units		Number of Units	Junior Special Units		Paid-in Capital		Accumulated Earnings (Deficit)			Subscription Receivable			Total
Balance, December 31, 2003	1,030	$	3,471	154	$	154	620	$	526	58	$	29	$	12,353	$	(17,012	)	$	(183	)	$	(662	)
Subscription receivable	—		—	—		—	—		—	—		—		—		—			183			183
Distributions to special unitholders	—		—	—		—	—		—	—		—		—		(143	)		—			(143	)
Net income	—		—	—		—	—		—	—		—		—		1,491			—			1,491

Balance, September 30, 2004	1,030	$	3,471	154	$	154	620	$	526	58	$	29	$	12,353	$	(15,664	)	$	—		$	869

	2004		2005		2006		2007		2008		Total
Bank debt	$	—	$	—	$	—	$	—	$	54,000	$	54,000
Commodity purchases		2,600		—		—		—		—		2,600

	$	2,600	$	—	$	—	$	—	$	54,000	$	56,600

		Copano Pipelines			Copano Processing			Corporate			Eliminations			Total
*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) loss from unconsolidated affiliate		(96	)		—			—			—			(96	)
	Segment gross margin		7,363			7,096			—			—			14,459
	Segment profit (loss)		2,889			3,250			(3,436	)		—			2,703
	Capital expenditures		2,312			84			—			—			2,396
*Three Months Ended September 30, 2003:*
	Sales to external customers	$	66,319		$	26,612		$	—		$	—		$	92,931
	Intersegment sales		29,420			9,799			—			(39,219	)		—
	Interest expense and other financing costs		708			958			2,149			—			3,815
	Depreciation and amortization		1,062			474			2			—			1,538
	Equity in (earnings) loss from unconsolidated affiliate		109			—			—			—			109
	Segment gross margin		6,308			(184	)		—			—			6,124
	Segment profit (loss)		2,056			(3,455	)		(2,175	)		—			(3,574	)
	Capital expenditures		826			912			—			—			1,738
*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) loss from unconsolidated affiliate		(263	)		—			—			—			(263	)
	Segment gross margin		21,397			12,608			—			—			34,005
	Segment profit (loss)		8,171			1,773			(8,453	)		—			1,491
	Segment assets		141,213			62,956			5,142			(35,267	)		174,044
	Capital expenditures		5,918			606			—			—			6,524
*Nine Months Ended September 30, 2003:*
	Sales to external customers	$	198,869		$	96,443		$	—		$	—		$	295,312
	Intersegment sales		108,706			29,054			—			(137,760	)		—
	Interest expense and other financing costs		2,083			2,872			2,148			—			7,103
	Depreciation and amortization		3,182			1,340			6			—			4,528
	Equity in (earnings) loss from unconsolidated affiliate		558			—			—			—			558
	Segment gross margin		20,869			205			—			—			21,074
	Segment profit (loss)		8,254			(9,317	)		(2,367	)		—			(3,430	)
	Capital expenditures		3,017			1,629			—			—			4,646

	Payment Due by Period
Type of Obligation	Total Obligation		Remainder Due in 2004		Due in 2005-2006		Due in 2007-2008		Thereafter
	(In thousands)
Long-term debt (1)	$	70,013	$	13,013	$	—	$	57,000	$	—
Interest (2)		9,390		976		5,700		2,714		—
Operating Leases		2,532		213		1,138		694		487

Total contractual cash obligations	$	81,935	$	14,202	$	6,838	$	60,408	$	487

		One Quarter		Four Quarters
Common units		$	2,815	$	11,261
Subordinated			1,408		5,631

	Total	$	4,223	$	16,892

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/Lice 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).
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		Employment Agreement between Copano/Operations, Inc. and James J. Gibson, III, dated as of October 1, 2004 (incorporated by reference to Exhibit 10.10 to Amendment No. 4 to Registration Statement on Form S-1/A filed November 2, 2004).
10.11		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).
10.12		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).

10.13		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).
10.14		Lease Agreement dated as of December 3, 1964, between The Plow Realty Company of Texas and Shell Oil Company (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.15		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).
10.16		Form of Restricted Unit Grant (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed December 15, 2004).
10.17*		Form of Grant of Options
31.1*		Sarbanes-Oxley Section 302 certification of John R. Eckel, Jr. for Copano Energy, L.L.C. for the September 30, 2004 Quarterly Report on Form 10-Q.
31.2*		Sarbanes-Oxley Section 302 certification of Matthew J. Assiff for Copano Energy, L.L.C. for the September 30, 2004 Quarterly Report on Form 10-Q.
32.1*		Sarbanes-Oxley Section 906 certification of John R. Eckel, Jr. for Copano Energy, L.L.C. for the September 30, 2004 Quarterly Report on Form 10-Q.
32.2*		Sarbanes-Oxley Section 906 certification of Matthew J. Assiff for Copano Energy, L.L.C. for the September 30, 2004 Quarterly Report on Form 10-Q.

		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