Copano Energy, L.L.C. 424B2 Prospectus for primary offering

Filed pursuant to Rule 424(b)(2)

Registration No. 333-138341

PROSPECTUS SUPPLEMENT

(To Prospectus dated November 1, 2006)

2,500,000 Common Units

Representing Limited Liability Company Interests

We are selling 2,500,000 common units representing limited liability company interests in Copano Energy, L.L.C. Our common units are listed on the Nasdaq Stock Market LLC, or the Nasdaq, under the symbol “CPNO.” The last reported sales price of our common units on the Nasdaq on November 30, 2006 was $59.11 per common unit.

Investing in our common units involves risk. Please read “Risk Factors” beginning onpage S-12 of this prospectus supplement and on page 1 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus are truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit		Total

Public offering price	$	59.11	$	147,775,000
Underwriting discount	$	2.51	$	6,280,438
Proceeds to Copano Energy, L.L.C. (before expenses)	$	56.60	$	141,494,562

We have granted the underwriters a30-day option to purchase up to an additional 375,000 common units to cover over-allotments, if any, at the public offering price per common unit, less the underwriting discounts and commissions. If the underwriters exercise the option in full, the total underwriting discounts and commissions will be $7,222,503 and the total proceeds to us, before expenses, will be $162,718,747.

The underwriters expect to deliver the common units on or about December 6, 2006.

Joint Book–Running Managers


UBS Investment Bank	Morgan Stanley

RBC Capital Markets

Lehman Brothers

Citigroup

Wachovia Securities

Banc of America Securities LLC

Deutsche Bank Securities

JPMorgan

KeyBanc Capital Markets

Sanders Morris Harris

The date of this prospectus supplement is November 30, 2006

This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this offering of common units. If the information about the common unit offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. We are offering to sell the common units, and seeking offers to buy the common units, only in jurisdictions where offers and sales are permitted. You should not assume that the information included in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the dates shown in these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since such dates.

In this prospectus supplement, we rely on and refer to certain publicly available information. Although we have no reason to believe this information is not reliable, we cannot guarantee the accuracy and completeness of the information and have not independently verified it.

TABLE OF CONTENTS


Prospectus Supplement
Summary			S-1
Non-GAAP Financial Measures			S-10
Risk Factors			S-12
Use of Proceeds			S-14
Capitalization			S-15
Price Range of Common Units and Distributions			S-16
Business			S-17
Directors and Officers			S-37
Tax Considerations			S-42
Underwriting			S-43
Legal Matters			S-46
Experts			S-46
Information Regarding Forward-Looking Statements			S-47
Where You Can Find More Information			S-48

Prospectus Dated November 1, 2006
About this Prospectus			ii
Copano Energy, L.L.C.			ii
Risk Factors			1
Information Regarding Forward-Looking Statements			15
Use of Proceeds			16
Ratios of Earnings to Fixed Charges			16
Description of Our Common Units			16
Description of Our Debt Securities			19
Cash Distribution Policy			27
Material Tax Consequences			32
Legal Matters			46
Experts			46
Where You Can Find More Information			46

SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement and the accompanying prospectus. It does not contain all of the information that you should consider before making an investment decision. You should read the entire prospectus supplement, the accompanying prospectus and the documents incorporated by reference for a more complete understanding of this offering. Please read “Risk Factors” beginning onpage S-12 of this prospectus supplement and page 1 of the accompanying prospectus for more information about important risks that you should consider before buying our common units. Unless the context otherwise indicates, the information included in this prospectus supplement assumes that the underwriters do not exercise their option to purchase additional common units.

Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us,” or like terms refer to Copano Energy, L.L.C. and its wholly-owned subsidiaries, including ScissorTail Energy, LLC. “ScissorTail” as used in this prospectus supplement refers to ScissorTail Energy, LLC. Unless the context requires otherwise, the pro forma financial information and operational data presented in this prospectus supplement give effect to: (i) our acquisition of the membership interests in ScissorTail on August 1, 2005 and related financings, including our February 2006 private placement of $225 million in aggregate principal amount of our 81/8% senior notes due 2016, and (ii) this offering and the application of the net proceeds as if they occurred on January 1, 2005. For a complete description of the adjustments we have made to arrive at the pro forma financial and operating information that we present in this prospectus supplement, please read “Summary Historical and Unaudited Pro Forma Financial and Operating Data” beginning onpage S-8 of this prospectus supplement.

COPANO ENERGY, L.L.C.

Our assets include over 4,950 miles of natural gas gathering and transmission pipelines and five natural gas processing plants, with over 800 million cubic feet per day of combined processing capacity. In addition to our natural gas pipelines, we own the104-mile Sheridan NGL Pipeline and lease the46-mile Brenham NGL Pipeline, which is expected to be operational in early 2007. Our assets include 144 miles of pipelines owned by Webb/Duval Gatherers, or “Webb Duval,” a partnership in which we own a 62.5% interest, and the Southern Dome processing plant owned by Southern Dome, LLC, or “Southern Dome,” in which we own a majority interest.

For the nine months ended September 30, 2006, we provided midstream services with respect to approximately 820 billion British thermal units per day, or BBtu/d, of natural gas and we generated $654.9 million of revenue, $140.7 million of total segment gross margin and $97.6 million of EBITDA. For the same period, we generated $48.6 million of net income and $72.6 million of operating income. For the definitions of total segment gross margin and EBITDA and a reconciliation of those items to the most directly comparable GAAP financial measures, please read “Non-GAAP Financial Measures.”

Our Operations

Our businesses are organized in the following operating segments:

Mid-Continent Operations Segment. The assets comprising our Mid-Continent Operations segment are located in active natural gas producing regions in central and eastern Oklahoma and are comprised of the assets we acquired through our purchase of ScissorTail on August 1, 2005. These assets include:


	•	3,364 miles of pipelines in eight primarily low-pressure gathering systems extending through counties encompassing an aggregate area of approximately 16,900 square miles, with combined throughput capacity of 231,000 Mcf/d as of September 30, 2006; and

S-1


	•	four processing plants, including the Southern Dome processing plant, with a combined inlet capacity of approximately 115,000 Mcf/d.

For the nine months ended September 30, 2006, average throughput volumes for our Mid-Continent Operations segment were 145,163 Mcf/d and average inlet volumes at our processing plants were65,761 Mcf/d. In addition to natural gas processed at our plants, we also deliver natural gas for processing at three third-party plants, for which we receive a portion of the product revenues. Average daily throughput volumes processed at third-party plants for our Mid-Continent Operations were 34,759 Mcf/d for the nine months ended September 30, 2006.

Texas Gulf Coast Pipelines Segment. The assets comprising our Texas Gulf Coast Pipelines segment include 1,594 miles of pipelines with combined throughput capacity of 922,800 Mcf/d as of September 30, 2006, including 219,000 Mcf/d of throughput capacity on Webb Duval, and are managed as four separate operating regions: the South Texas, Coastal Waters, Central Gulf Coast, and Upper Gulf Coast regions. For the nine months ended September 30, 2006, we averaged net throughput volume of 337,626 Mcf/d of natural gas through these pipeline assets.

Texas Gulf Coast Processing Segment. The assets comprising our Texas Gulf Coast Processing segment include our Houston Central Processing Plant, our Sheridan NGL Pipeline and the46-mile Brenham NGL Pipeline that we lease from Kinder Morgan Energy Partners, L.P. Our Houston Central Processing Plant, which has the capacity to process approximately 700,000 Mcf/d of natural gas, is the second largest natural gas processing plant in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. Our Houston Central Processing Plant removes NGLs from the natural gas supplied by the Kinder Morgan Texas Pipeline (KMTP)Laredo-to-Katy pipeline, which it straddles, and the pipelines in our Central Gulf Coast Region gathering systems. To the extent commercially desirable, natural gas liquids, or NGLs, are separated into select component NGL products at our Houston Central Processing Plant and are sold to third parties at the plant tailgate or transported for sale on our Sheridan NGL Pipeline and, beginning in early 2007, on our Brenham NGL Pipeline. For the nine months ended September 30, 2006, we averaged net natural gas throughput volume of 487,469 Mcf/d at our Houston Central Processing Plant.

Recent Developments

November 2006 Hedge Activity

On November 21, 2006, we expanded our risk management portfolio by purchasing natural gas call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central Processing Plant. The call spread options represent the purchase of natural gas call options and the concurrent sale of natural gas call options with respect to the same volumes at a higher strike price. The call spread options will be settled monthly over a five-year period beginning January 2007 and ending December 2011. We purchased the call spread options on November 21, 2006 from two investment grade counterparties in accordance with our risk management policy. These options were implemented as cash flow hedges to mitigate the impact of increases in natural gas prices on our Texas Gulf Coast Processing Segment. We paid approximately $9.2 million for the newly acquired call spread options. Please read “Business — Risk Management” for a more detailed description of the call spread options and our risk management program.

Third Quarter Results

On November 7, 2006, we announced a 130% increase in our operating income to $31.1 million for the third quarter of 2006 as compared to the same period in 2005. Thisyear-over-year performance reflects the full quarter inclusion of our Mid-Continent Operations segment, significant volume growth in our Mid-Continent and Texas Gulf Coast operating regions as well as favorable market conditions for our Texas Gulf Coast Processing segment. For the three months ended September 30, 2006, we generated $231.3 million of revenue, total segment gross margin of $56.0 million and $40.0 million of EBITDA. For the same period, we generated $22.3 million in net income and $31.1 million of operating income. For the definition of gross margin and EBITDA and a reconciliation of these items to the most directly comparable GAAP financial measures, please read “Non-GAAP Financial Measures.”

S-2

Declaration of Distribution

On October 18, 2006, our Board of Directors declared a cash distribution for the three months ended September 30, 2006 of $0.75 per unit for all outstanding common and subordinated units. This represents an increase of over 11% from our previous quarterly distribution, a 50% increase over our quarterly distribution for the third quarter of 2005 and was the seventh consecutive increase in our quarterly cash distribution since our initial public offering. The distribution, totaling $13.8 million, was paid on November 14, 2006 to holders of record at the close of business on November 1, 2006.

Amendment to Revolving Credit Facility and Entry Into Unsecured Term Loan

On September 20, 2006, we amended our revolving credit facility to, among other things, permit us to incur additional unsecured indebtedness so long as the indebtedness has a maturity of not earlier than 91 days after the maturity date of our revolving credit facility and we are in compliance with all relevant covenants on a pro forma basis. This amendment enabled us to enter into a $100 million unsecured term loan on September 29, 2006. We used the proceeds of our unsecured term loan to reduce the outstanding indebtedness under our revolving credit facility from $150 million to $50 million as of September 30, 2006 and concurrently reduced the commitment amount under our revolving credit facility from $350 million to $200 million. The interest rate on borrowings under our unsecured term loan was 8.4% as of November 21, 2006. We plan to repay in full the outstanding indebtedness under our unsecured term loan with a portion of the net proceeds of this offering. Please read “Use of Proceeds.”

Our Business Strategy

Our management team is committed to improving cash flow from our existing assets, pursuing complementary acquisition and organic expansion opportunities, and managing our commodity risk exposure. Key elements of our strategy include:


	•	Pursuing growth from our existing assets;

	•	Pursuing complementary acquisitions and organic expansion opportunities;

	•	Reducing the sensitivity of our cash flows to commodity price fluctuations;

	•	Exploiting the operating flexibility of our assets; and

	•	Expanding our geographic scope into new regions where our growth strategy can be applied.

Competitive Strengths

We believe we are well-positioned to execute our business strategy successfully based on the following competitive strengths:


	•	Our assets are strategically located in active natural gas supply areas;

	•	Our assets have additional capacity;

	•	We provide an integrated and comprehensive package of midstream services;

	•	Our assets and contracts, including our conditioning capability at our Houston Central Processing Plant, provide us with the operating flexibility to mitigate processing margin risk;

	•	We have knowledgeable and experienced employees with significant ownership interests in us; and

	•	Our cost of equity capital is not burdened by incentive distribution rights to a general partner.

Our Offices

Our principal executive offices are located at 2727 Allen Parkway, Suite 1200, Houston, Texas 77019, and our phone number is(713) 621-9547. Our website address is www.copanoenergy.com. Information on our website is not incorporated in this prospectus supplement.

S-3

Our Structure

We are a Delaware limited liability company, and our common units are listed on the Nasdaq under the symbol “CPNO.” The chart below depicts our organization and ownership structure as of November 15, 2006 after giving effect to this offering of 2,500,000 common units.


(1)		Includes interests over which management has votingand/or dispositive control or in which management has a pecuniary interest. Excludes outstanding awards under our long-term incentive plan as of November 15, 2006, including 146,718 restricted units and 604,279 options to acquire common units, of which 122,460 are currently exercisable.

(2)		Includes subordinated units, which are not publicly traded. Our subordinated units will convert into common units on aone-for-one basis at the end of the subordination period. We expect to satisfy the financial tests required by our limited liability company agreement to end the subordination period with the payment of our fourth quarter distribution for 2006. We expect to make this distribution on or about February 14, 2007. Certain members of management or their affiliates own an aggregate of 1,428,078 subordinated units, representing a 6.8% pro forma membership interest in us, and certain institutional investors and their transferees own an aggregate of 2,091,048 subordinated units, representing a 10% pro forma membership interest in us. Please read “— The Offering — Subordination Period.”

(3)		If the underwriters’ over-allotment option is exercised in full, the ownership interest of the public unitholders will increase from 18,447,103 common and subordinated units to 18,822,103 common and subordinated units, representing a 89% membership interest in us, and the aggregate ownership interest of our officers, directors and employees will be 11%.

(4)		Our Mid-Continent Operations segment includes our majority limited liability company interest in Southern Dome.

(5)		Our Texas Gulf Coast Pipelines segment includes our 62.5% partnership interest in Webb Duval.

S-4

THE OFFERING


Common Units Offered By Us		2,500,000, common units; 2,875,000 common units if the underwriters exercise in full their option to purchase an additional 375,000 common units.

Units Outstanding After this Offering		17,374,457 common units, or 17,749,457 common units if the underwriters exercise in full their option to purchase an additional 375,000 common units, and 3,519,126 subordinated units.

Use of Proceeds		We will use the net proceeds from this offering:

		• to repay in full the $100.0 million of indebtedness outstanding under our unsecured term loan; and

		• for general company purposes, including reducing amounts outstanding under our senior secured revolving credit facility, entering into new hedge arrangements as market conditions warrant and funding capital expenditures.

		Please read “Use of Proceeds.”

		We will use all the net proceeds from any exercise of the underwriters’ over-allotment option for general company purposes.

		We entered into our unsecured term loan to reduce outstanding indebtedness under our senior secured revolving credit facility from $150 million to $50 million.

		An affiliate of Banc of America Securities LLC is the lender under our unsecured term loan and will receive greater than 10% of the net proceeds of this offering through our repayment of that facility. In addition, affiliates of certain of the underwriters participating in this offering are counterparties with respect to our existing commodity hedge arrangements. Please read “Underwriting — Relationships/NASD Conduct Rules.”

Cash Distributions		Under the terms of our limited liability company agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our board of directors in its reasonable discretion. We refer to this cash as “available cash,” and we define it in our limited liability company agreement. In general, we will pay any cash distributions we make each quarter in the following manner:

		• first, to the common units until each common unit has received a minimum quarterly distribution of $0.40 plus any arrearages in the payment of the minimum quarterly distribution from prior quarters;

		• second, to the subordinated units until each subordinated unit has received a minimum quarterly distribution of $0.40; and

		• thereafter, to all holders pro rata.

		Our quarterly distribution with respect to the third quarter 2006 was $0.75 per unit for all outstanding common and subordinated units.

S-5


Subordination Period		Our subordinated units will convert into common units on aone-for-one basis at the end of the subordination period. We expect to satisfy the financial tests required by our limited liability company agreement to end the subordination period with the payment of our fourth quarter distribution for 2006. We expect to make this distribution on or about February 14, 2007.

		Certain members of management or their affiliates own an aggregate of 1,428,078 subordinated units, representing a 6.8% pro forma membership interest in us, and certain institutional investors and their transferees own an aggregate of 2,091,048 subordinated units, representing a 10% pro forma membership interest in us. Please read “— The Offering — Subordination Period.”

Agreement to be Bound by Limited Liability Company Agreement; Voting Rights		By purchasing a common unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, as a unitholder you will be entitled to vote on the following matters:

		• the annual election, by cumulative voting, of members of our board of directors;

		• the issuance of units of senior rank or, in certain circumstances, equal rank to the common units during the subordination period;

		• specified amendments to our limited liability company agreement;

		• a merger involving our company or the sale of all or substantially all of our assets; and

		• a dissolution of our company.

Estimated Ratio of Taxable Income to Distributions		We estimate that if you hold the common units that you purchase in this offering through December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 20% or less of the cash distributed to you with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership” on page 34 of the accompanying prospectus for the basis of this estimate.

Exchange Listing		Our common units are listed on the Nasdaq under the symbol “CPNO.”

S-6

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA

The following table sets forth our summary historical financial and our summary unaudited pro forma consolidated financial data for the periods and as of the dates indicated. Our summary historical financial data as of September 30, 2006 and for the nine months ended September 30, 2006 and 2005 are derived from the unaudited consolidated financial statements of Copano Energy, L.L.C. appearing in our quarterly report onForm 10-Q for the quarter ended September 30, 2006 incorporated by reference into this prospectus supplement. Our summary historical financial data as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2005, 2004 and 2003 are derived from the audited consolidated financial statements of Copano Energy, L.L.C. appearing in our annual report onForm 10-K for the year ended December 31, 2005 incorporated by reference into this prospectus supplement.

The summary unaudited pro forma statement of operations data for the nine months ended September 30, 2006 and for the year ended December 31, 2005 give effect to the following transactions as if such transactions occurred on January 1, 2005:


	•	our acquisition of ScissorTail on August 1, 2005 and relating financings, including our February 2006 private placement of $225 million in aggregate principal amount of our 81/8% senior notes due 2016; and

	•	this offering of common units and the application of the net proceeds therefrom as described in “Use of Proceeds.”

The summary unaudited pro forma balance sheet data as of September 30, 2006 give effect to our purchase of $9.2 million of natural gas call spread options on November 21, 2006 and to this offering of common units and the application of the net proceeds therefrom as described in “Use of Proceeds” as though it occurred on September 30, 2006. Please read “— Recent Developments — November 2006 Hedge Activity” for a more detailed description of our recent hedge activities.

The pro forma adjustments are based upon available information and certain assumptions that we consider reasonable. The pro forma statement of operations data are not necessarily indicative of the results of operations that would have been achieved had the transactions reflected herein been consummated on the dates indicated or that will be achieved in the future.

S-7

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA


																Pro Forma
																Nine Months
	Nine Months Ended															Ended			Year Ended
	September 30,						Year Ended December 31,									September 30,			December 31,
	2006			2005(1)			2005(1)			2004			2003			2006			2005
Statement of Operations Data:	(Dollars in Millions)
Revenues	$	654.9		$	452.6		$	747.7		$	437.7		$	384.6		$	654.9		$	933.0
Costs and Expenses:
Cost of Sales		514.2			394.2			643.6			386.1			353.4			514.2			789.5
Operations and Maintenance Expenses		23.5			11.3			18.5			12.5			10.9			23.5			25.7
Depreciation and Amortization		23.7			9.4			17.0			7.3			6.1			23.7			30.5
General and Administrative Expenses		19.9			11.4			18.1			9.2			5.8			19.9			20.8
Taxes Other than Income		1.6			0.7			1.2			0.8			0.9			1.6			1.3
Equity in (Earnings) Loss from Unconsolidated Affiliates		(0.6	)		(0.7	)		(0.9	)		(0.4	)		0.1			(0.6	)		(0.9	)

Operating Income		72.6			26.3			50.2			22.2			7.4			72.6			66.1
Interest Income and Other		1.3			0.3			0.6			0.1			—			1.3			0.8
Interest and Other Financing Costs		(25.3	)		(10.5	)		(20.5	)		(23.2	)		(12.1	)		(17.6	)		(23.2	)

Net Income (Loss)	$	48.6		$	16.1		$	30.3		$	(0.9	)	$	(4.7	)	$	56.3		$	43.7

Balance Sheet Data (at period end):
Cash and Cash Equivalents	$	34.6		$	29.8		$	25.3		$	7.0		$	4.6		$	66.2	(2)
Property, Plant and Equipment, Net		555.6			532.1			532.3			119.7			117.0			555.6
Total Assets		807.2			775.6			792.8			178.4			161.7			847.3	(2)
Total Debt, including Current Maturities		375.0			402.0			398.0			57.0			57.9			275.0
Total Members’ Capital		322.1			260.7			281.8			82.4			(0.7	)		462.3	(2)
Other Financial Data:
Segment Gross Margin:
Mid-Continent Operations	$	72.1		$	14.9		$	40.7		$	—		$	—		$	72.1		$	80.1
Texas Gulf Coast Pipelines		29.4			23.3			32.9			30.1			27.6			29.4			32.9
Texas Gulf Coast Processing		38.9			20.5			30.2			21.5			3.6			38.9			30.2
Other		0.3			(0.3	)		0.3			—			—			0.3			0.3

Total Segment Gross Margin	$	140.7		$	58.4		$	104.1		$	51.6		$	31.2		$	140.7		$	143.5

EBITDA	$	97.6		$	36.0		$	67.8		$	29.6		$	13.5		$	97.6		$	97.4

Maintenance Capital Expenditures(3)	$	7.3		$	2.8		$	5.4		$	1.8		$	2.3		$	7.3		$	7.3
Expansion Capital Expenditures(4)		35.6			484.9			487.6			7.1			3.9			35.6			488.6

Total Capital Expenditures	$	42.9		$	487.7		$	493.0		$	8.9		$	6.2		$	42.9		$	495.9

Operating Data:
Mid-Continent Operations:
Pipeline Throughput (MMBtu/d)(5)		174,772			155,153			158,334			—			—
Plant Inlet Throughput (MMBtu/d)(5)		122,628			102,706			106,877			—			—
NGLs Produced (Bbls/d)(5)		11,475			8,656			9,146			—			—
Texas Gulf Coast Pipelines(6):
Pipeline Throughput (MMBtu/d)		246,212			230,150			232,280			239,770			256,556
Texas Gulf Coast Processing:
Plant Inlet Throughput (MMBtu/d)		513,567			561,609			561,085			559,939			502,057
NGLs Produced (Bbls/d)		14,446			13,661			13,066			15,373			7,280

S-8


(1)		Our summary financial and operating data as of and for the nine months ended September 30, 2005 and as of and for the year ended December 31, 2005 include the results of our Mid-Continent Operations from August 1, 2005 (the date we acquired ScissorTail).

(2)		Pro forma Cash and Cash Equivalents, Total Assets and Total Members’ Capital for the nine months ended September 30, 2006 reflect the payment of approximately $720,000 of expenses payable by us in connection with this offering.

(3)		Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

(4)		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. Costs for repairs and minor renewals to maintain facilities in operating condition, and which do not extend the useful life of existing assets, are considered operations and maintenance expenses (and not expansion capital expenditures) and are expensed as incurred.

(5)		Plant inlet throughput and NGLs produced represent total volumes processed and produced by our Mid-Continent Operations segment at all plants, including plants owned by our Mid-Continent Operations segment and plants owned by third parties. For the nine months ended September 30, 2006, plant inlet throughput averaged 80,140 MMBtu/d and NGLs produced averaged 7,746 barrels per day, or Bbls/d, for plants owned by our Mid-Continent Operations segment. For the period from August 1, 2005 through December 31, 2005, plant inlet throughput averaged 65,962 MMBtu/d and NGLs produced averaged 5,500 Bbls/d for plants owned by our Mid-Continent Operations segment. For the period from August 1, 2005 through September 30, 2005, plant inlet throughput averaged 63,059 MMBtu/d and NGLs produced averaged 4,959 Bbls/d for plants owned by our Mid-Continent Operations segment.

(6)		Excludes results and volumes associated with our interest in Webb Duval. Volumes transported by Webb Duval, net of intercompany volumes, were 116,429 MMBtu/d and 123,645 MMBtu/d for the nine months ended September 30, 2006 and 2005, respectively, and 121,864 MMBtu/d, 118,873 MMBtu/d and 108,640 MMBtu/d for the years ended December 31, 2005, 2004 and 2003, respectively.

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NON-GAAP FINANCIAL MEASURES

We include in this prospectus supplement the non-GAAP financial measures of total segment gross margin and EBITDA. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define total segment gross margin as revenue less cost of sales. Cost of sales includes the following costs and expenses:


	•	cost of natural gas and NGLs purchased by us from third parties;

	•	cost of natural gas and NGLs purchased by us from affiliates;

	•	costs we pay third parties to transport our volumes; and

	•	costs we pay our affiliates to transport our volumes.

We view total segment gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses. The GAAP measure most directly comparable to total segment gross margin is operating income.

The following presents a reconciliation of the non-GAAP financial measure of total segment gross margin (which consists of the sum of individual segment gross margins) to operating income on a historical basis for each of the periods indicated.


	Three																	Pro Forma
	Months																	Nine Months
	Ended			Nine Months Ended														Ended			Year Ended
	September 30,			September 30,						Year Ended December 31,								September 30,			December 31,
	2006			2006			2005			2005			2004			2003		2006			2005
	(In Millions)

Reconciliation of Total Segment Gross Margin to Operating Income:
Operating Income	$	31.1		$	72.6		$	26.3		$	50.2		$	22.2		$	7.4	$	72.6		$	66.1
Plus:
Operations and Maintenance Expenses		8.5			23.5			11.3			18.5			12.5			10.9		23.5			25.7
Depreciation and Amortization		8.2			23.7			9.4			17.0			7.3			6.1		23.7			30.5
General and Administrative Expenses		8.1			19.9			11.4			18.1			9.2			5.8		19.9			20.8
Taxes Other Than Income		0.6			1.6			0.7			1.2			0.8			0.9		1.6			1.3
Equity in (Earnings) Loss of Unconsolidated Affiliates		(0.5	)		(0.6	)		(0.7	)		(0.9	)		(0.4	)		0.1		(0.6	)		(0.9	)

Total Segment Gross Margin	$	56.0		$	140.7		$	58.4		$	104.1		$	51.6		$	31.2	$	140.7		$	143.5

We define EBITDA as net income (loss) plus interest expense and other financing costs, provision for income taxes and depreciation and amortization expense.

EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:


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

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

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

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

EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our banks and is used to compute our financial covenants. 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 EBITDA may not be comparable to EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA in the same manner as we do. We have reconciled EBITDA to net income and cash flows from operating activities.

The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities on a historical basis for each of the periods indicated.


	Three																		Pro Forma
	Months																		Nine Months
	Ended																		Ended		Year Ended
	September 30,			Nine Months Ended September 30,						Year Ended December 31,									September 30,		December 31,
	2006			2006			2005			2005			2004			2003			2006		2005
	(In Millions)

Reconciliation of EBITDA to Net Income (Loss):
Net Income (Loss)	$	22.3		$	48.6		$	16.1		$	30.3		$	(0.9	)	$	(4.7	)	$	56.3	$	43.7
Plus:
Depreciation and Amortization		8.2			23.7			9.4			17.0			7.3			6.1			23.7		30.5
Interest and Other Financing Costs		9.5			25.3			10.5			20.5			23.2			12.1			17.6		23.2

EBITDA	$	40.0		$	97.6		$	36.0		$	67.8		$	29.6		$	13.5		$	97.6	$	97.4

Reconciliation of EBITDA to Cash Flow from Operating Activities:
Cash Flow from Operating Activities	$	36.7		$	96.6		$	12.1		$	0.3		$	17.7		$	15.3
Plus:
Cash Paid for Interest and Other Financing Costs		7.4			21.8			6.8			14.7			4.1			3.0
Risk Management Assets		(4.0	)		(6.9	)		3.5			42.6			—			—
(Decrease) Increase in Working Capital		(0.6	)		(14.5	)		12.9			9.3			7.4			(4.7	)
Less:
Equity in (Earnings) Loss of Unconsolidated Affiliates		(0.5	)		(0.6	)		(0.7	)		(0.9	)		(0.4	)		0.1

EBITDA	$	40.0		$	97.6		$	36.0		$	67.8		$	29.6		$	13.5

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RISK FACTORS

An investment in our common units involves risks. You should carefully consider all of the information contained in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference as provided under “Where You Can Find More Information,” including our annual report onForm 10-K for the year ended December 31, 2005 and our quarterly report onForm 10-Q for the quarter ended September 30, 2006, and the risk factors described under “Risk Factors” in the accompanying prospectus. This prospectus supplement, the accompanying prospectus and the documents incorporated by reference also contain forward-looking statements that involve risks and uncertainties. Please read “Information Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors, including the risks described below, elsewhere in this prospectus supplement, in the accompanying prospectus and in the documents incorporated by reference. If any of these risks occur, our business, financial condition or results of operation could be adversely affected.

We may not have sufficient cash from operations each quarter to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. Under the terms of our limited liability company agreement, we must pay our operations and maintenance expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


	•	the amount of natural gas gathered and transported on our pipelines;

	•	the throughput volumes at our processing, conditioning and treating plants;

	•	the price of natural gas, NGLs and crude oil;

	•	the relationship between natural gas and NGL prices;

	•	the level of our operating costs;

	•	the weather in our operating areas;

	•	the level of competition from other midstream energy companies; and

	•	the fees we charge and the margins we realize for our services.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


	•	the level of capital expenditures we make;

	•	the cost of acquisitions, if any;

	•	our debt service requirements;

	•	fluctuations in our working capital needs;

	•	restrictions on distributions contained in our senior secured revolving credit facility and the indenture governing our senior notes;

	•	our ability to make eligible working capital borrowings under our senior secured revolving credit facility to pay distributions;

	•	prevailing economic conditions; and

	•	the amount of cash reserves established by our board of directors for the proper conduct of our business.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and eligible working capital borrowings, and is not solely a function of

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profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.


	*Our profitability depends upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.*

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005 and the nine months ended September 30, 2006, the Houston Ship Channel, or HSC, natural gas index price ranged from a high of $10.92 per MMBtu to a low of $5.74 per MMBtu and from a high of $8.68 per MMBtu to a low of $5.69 per MMBtu, respectively. A composite of the Oil Price Information Service, or OPIS, Mt. Belvieu monthly average NGL price based upon our average NGL composition during the year ended December 31, 2005 and the nine months ended September 30, 2006 ranged from a high of approximately $1.116 per gallon to a low of approximately $0.729 per gallon and from a high of approximately $1.128 per gallon to a low of approximately $0.866 per gallon, respectively. For a more complete description of our risks related to fluctuations in commodity prices, please refer to “Risk Factors” in the prospectus accompanying this prospectus supplement.

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USE OF PROCEEDS

We will receive net proceeds of approximately $140.8 million from the sale of the 2,500,000 common units in this offering, after deducting the underwriting discount and approximately $720,000 of offering expenses payable by us.

We will use the net proceeds from this offering:


	•	to repay in full the $100.0 million of indebtedness outstanding under our unsecured term loan; and

	•	for general company purposes, including reducing amounts outstanding under our senior secured revolving credit facility, entering into new hedge arrangements as market conditions warrant or funding capital expenditures.

On September 29, 2006, we entered into our unsecured term loan with Banc of America Bridge LLC and certain of its affiliates to reduce outstanding indebtedness under our senior secured revolving credit facility from $150 million to $50 million. Our unsecured term loan matures on November 1, 2010 and the interest rate on borrowings under our unsecured term loan was 8.4% as of November 21, 2006. Our senior secured revolving credit facility matures August 1, 2010 and the interest rate on borrowings under this facility was 6.5% as of November 21, 2006 after giving effect to related interest rate swaps.

We will use the net proceeds from any exercise of the underwriters’ over-allotment option for general company purposes.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2006:


	•	on a historical basis; and

	•	on an as adjusted basis, after giving effect to our purchase of $9.2 million of natural gas call spread options on November 21, 2006 and the issuance of the common units offered hereby and the application of the net proceeds therefrom as described in “Use of Proceeds.” Please read “Summary — Recent Developments — November 2006 Hedge Activity” for a more detailed description of our recent hedge activities.

This table should be read in conjunction with, and is qualified in its entirety by reference to, our historical financial statements and the accompanying notes included in our quarterly report onForm 10-Q for the quarter ended September 30, 2006, which is incorporated by reference herein.


	As of September 30, 2006
	Historical		As Adjusted(2)
	(In Millions)

Cash and Cash Equivalents	$	34.6	$	66.2

Debt:
Unsecured Term Loan	$	100.0	$	—
Senior Secured Revolving Credit Facility(1)		50.0		50.0
81/8% Senior Notes Due 2016		225.0		225.0

Total Debt		375.0		275.0
Total Members’ Capital		322.1		462.3

Total Capitalization	$	697.1	$	737.3


(1)		Total commitments under our senior secured revolving credit facility are $200 million. We had $50 million of outstanding indebtedness under our revolving credit facility as of November 21, 2006. This amount does not include $10 million of borrowings on November 22, 2006, of which $9.2 million was incurred in connection with our newly acquired hedges.

(2)		Cash and Cash Equivalents (As Adjusted) reflects the application of the proceeds from this offering, after deducting the underwriting discount and approximately $720,000 of offering expenses payable by us, as described in “Use of Proceeds.”

This table does not reflect the issuance of up to 375,000 common units that may be sold to the underwriters upon exercise of their option to purchase additional common units, the proceeds of which will be used for general corporate purposes. Please read “Use of Proceeds.”

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

At the close of business on November 16, 2006, there were 37 holders of record of our common units (excluding restricted common units awarded under our long-term incentive plan). Our common units are traded on the Nasdaq under the symbol “CPNO.”

As of November 30, 2006, 3,519,126 subordinated units were outstanding. The subordinated units are held by (i) certain members of our management or their affiliates, (ii) merchant banking funds managed by affiliates of Credit Suisse, (iii) affiliated funds of Encap Investments, L.P. (i, ii and iii collectively referred to as the “pre-IPO investors”) and (iv) certain pre-IPO investor transferees. Our subordinated units will convert into common units on aone-for-one basis at the end of the subordination period. We expect to satisfy the financial tests required by our limited liability company agreement to end the subordination period with the payment of our distribution for the fourth quarter 2006. We expect to make this distribution on or about February 14, 2007. Certain members of management or their affiliates own an aggregate of 1,428,078 subordinated units, representing a 6.8% pro forma membership interest in us, and certain institutional investors and their transferees own an aggregate of 2,091,048 subordinated units, representing a 10% pro forma membership interest in us. Please read “— The Offering — Subordination Period.”

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the Nasdaq, and quarterly cash distributions paid or to be paid to our unitholders. The last reported closing sales price of our common units on the Nasdaq on November 30, 2006 was $59.11 per common unit.


	Sales Price Ranges				Cash Distributions
	High		Low		per Unit(1)

2006
Fourth Quarter (through November 30, 2006)	$	63.34	$	52.75		N/A
Third Quarter	$	54.80	$	46.73	$	0.75
Second Quarter	$	49.76	$	43.27	$	0.675
First Quarter	$	44.95	$	38.10	$	0.60
2005
Fourth Quarter	$	39.90	$	34.10	$	0.55
Third Quarter	$	44.60	$	36.00	$	0.50
Second Quarter	$	36.90	$	27.76	$	0.45
First Quarter	$	31.48	$	25.47	$	0.42
2004
Fourth Quarter	$	28.75	$	23.06	$	0.20	(2)


(1)		Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end.

(2)		Reflects the pro rata portion of the $0.40 per unit initial distribution rate, representing the period from the November 15, 2004 closing of our initial public offering through December 31, 2004.

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BUSINESS

General

Our assets include over 4,950 miles of natural gas gathering and transmission pipelines and five natural gas processing plants, with over 800 million cubic feet per day of combined processing capacity. In addition to our natural gas pipelines, we own the104-mile Sheridan NGL Pipeline and lease the46-mile Brenham NGL Pipeline, which is expected to be operational in early 2007. Our assets also include 144 miles of pipelines owned by Webb Duval, a partnership in which we own a 62.5% interest, and the Southern Dome processing plant owned by Southern Dome, in which we own a majority interest.

For the nine months ended September 30, 2006, we provided midstream services with respect to approximately 820 BBtu/d of natural gas and we generated $654.9 million of revenue, $140.7 million of total segment gross margin and $97.6 million of EBITDA. For the same period, we generated $48.6 million of net income and $72.6 million of operating income. For the definitions of total segment gross margin and EBITDA and a reconciliation of those items to the most directly comparable GAAP financial measures, please read “Non-GAAP Financial Measures.”

Business Strategy

Our management team is committed to exploiting new business opportunities associated with our existing assets, pursuing complementary acquisition and organic expansion opportunities, and managing our commodity risk exposure. Key elements of our strategy include:


	•	Pursuing growth from our existing assets. Our pipelines and processing plants have excess capacity, which provides us with opportunities to increase throughput volume with minimal incremental costs. We seek to increase cash flow from our existing assets by aggressively marketing our services to producers to connect new supplies of natural gas and increase volumes and utilization.

	•	Pursuing complementary acquisitions and organic expansion opportunities. We seek to use our acquisition and integration experience to continue to make complementary acquisitions of midstream assets in our operating areas that provide opportunities to expand either the acquired assets or our existing assets to increase utilization. We pursue acquisitions that we believe will allow us to capitalize on our existing infrastructure, personnel, and producer and customer relationships to strengthen our existing integrated package of services. Also, we seek to expand our assets where appropriate to meet increased demand for our midstream services.

	•	Reducing the sensitivity of our cash flows to commodity price fluctuations. Because of the volatility of natural gas and NGL prices, we attempt to structure our contracts in a manner that allows us to achieve positive gross margins in a variety of market conditions. In our contracts for services provided by our Texas Gulf Coast Processing segment, we focus on arrangements pursuant to which we are paid a fee to condition natural gas when processing is economically unattractive. In our contracts with producers within our Texas Gulf Coast Pipelines and Mid-Continent Operations segments, we focus on arrangements pursuant to which the fee received for the services we deliver is sufficient to provide us with positive operating margins irrespective of commodity prices.

In addition, our commodity risk management activities are designed to hedge our exposure to price risk and meet debt service requirements, required capital expenditures, distribution objectives and similar requirements despite fluctuations in commodity prices. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions.

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	•	Exploiting the operating flexibility of our assets. We can modify the operation of our assets to maximize our cash flows. For example, our ability to condition natural gas at our Houston Central Processing Plant, rather than fully process it, provides us with significant benefits during periods when fully processing natural gas is not economical. We continually monitor natural gas and NGL prices to quickly switch between processing and conditioning modes when it is economically appropriate to do so. In addition, we will continue to utilize our ability to reject ethane at our Houston Central Processing Plant, Paden Plant and Glenpool Plant, as market conditions warrant. We also consider alternative natural gas sales options at the tailgate of our Houston Central Processing Plant and alternative sources of natural gas supply on our Upper Gulf Coast pipeline system.

	•	Expanding our geographic scope into new regions where our growth strategy can be applied. We pursue opportunities to acquire assets in new regions where we believe growth opportunities are attractive and our business strategies could be applied.

Competitive Strengths

We believe we are well-positioned to execute our business strategy successfully based on the following competitive strengths:


	•	Our assets are strategically located in active natural gas supply areas. Our assets are strategically located in natural gas producing regions in Texas and Oklahoma, which are characterized by consistently high levels of drilling activity. In particular, our Mid-Continent Operations segment has experienced significant throughput volume growth, with average throughput volume increasing 15.6% in the nine months ended September 30, 2006 compared to the corresponding period in 2005. We believe that ongoing development, including within the Hunton limestone formation, will result in throughput volume growth for the next several years. The leading producer by volume in our Mid-Continent Operations segment has dedicated to us all of its production from its existing and future leases within a1.1-million acre area pursuant to a contract that extends until mid-2020.

Our gathering and transmission pipelines have access to a variety of intrastate and interstate pipelines, as well as certain other end-user markets. We believe our pipeline asset platform, together with our efficient and strategically located natural gas processing plants, provides us with a competitive advantage in capturing new supplies of natural gas. Our existing position is also advantageous because constructing significant pipelines and processing plants in these regions is challenging due to existing regulatory constraints and difficulties in obtainingrights-of-way.


	•	Our assets have additional capacity. For the nine months ended September 30, 2006, our Texas Gulf Coast Pipelines segment utilized an average of 37% of throughput capacity of its pipeline assets, as currently configured (including capacity of pipelines owned by Webb Duval), and our Texas Gulf Coast Processing segment utilized an average of 70% of inlet volume capacity at the Houston Central Plant. For the same period, our Mid-Continent Operations’ segment utilized an average of 63% of throughput capacity of its pipeline assets, as currently configured, and its three wholly-owned natural gas processing plants utilized an average of 66% of their inlet volume capacity. By continuing to connect additional natural gas supplies to our gathering pipelines and our processing plants, we believe that we can take advantage of our existing asset platform to increase utilization and thereby increase cash flow.

	•	We provide an integrated and comprehensive package of midstream services. We provide natural gas gathering, transportation, compression, dehydration, treating, conditioning and processing services. We believe some of our competitors provide only certain of these services and that our ability to furnish our customers with a comprehensive package of midstream services enables our customers to attach their wells to our gathering systems more efficiently and quickly and gives us an advantage in competing for new supplies of natural gas.

	•	Our contracts and assets, including our conditioning capability at our Houston Central Processing Plant, provide us with the operating flexibility to mitigate processing margin risk. Our ability to condition natural gas in our Texas Gulf Coast Processing segment, rather than fully process it, provides

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		us with significant benefits during periods when processing natural gas is not economic (when the price of natural gas is high relative to NGL prices). Our Houston Central Processing Plant is equipped to condition natural gas, or to minimize the level of NGLs removed from the natural gas stream, reducing its fuel consumption rate while still meeting downstream pipeline hydrocarbon dew point specifications. Our processing contract arrangements allow us to exercise this conditioning ability. As a result, when we are conditioning natural gas, the combination of reduced NGL removal and reduced fuel consumption at our Houston Central Processing Plant allows us to preserve a greater portion of the value of the natural gas. We are not exposed to significant processing margin risk at our Mid-Continent Operations segment as it operates predominantly underpercentage-of-proceeds arrangements.


	•	We have knowledgeable and experienced employees with significant ownership interests in us. Our management employees have an average of 24 years of energy industry experience and many of our employees operated or were associated with our assets before we acquired them. Our employees owned, directly or indirectly, approximately 11% on a pro forma basis of our outstanding units as of November 15, 2006 (excluding outstanding awards under our long-term incentive plan as of November 15, 2006, which include 134,718 restricted units and 604,279 options to acquire common units, of which 122,460 are currently exercisable). All of our employees, with the exception of our Chairman and Chief Executive Officer, have been granted restricted units or options to acquire common units under our long-term incentive plan. Accordingly, we believe our management team and non-management employees have significant incentive to continue to maintain and increase our cash flows.

	•	Our cost of equity capital is not burdened by incentive distribution rights to a general partner. Unlike most public pipeline partnerships, neither our management nor any of our investors have incentive distribution rights, or IDRs, that would provide them with an increasing percentage of cash distributions as the amount of our quarterly distributions per unit increases. As a result, when we issue additional common units, the distributions we will make on those units are not burdened by a concurrent payment of an incentive distribution to management or a general partner. In addition, as our cash flows increase, more of this increase is available for distribution to you than would be the case if we had IDRs.

Our Operations

Our businesses are organized in the following operating segments:

Mid-Continent Operations Segment. The assets comprising our Mid-Continent Operations segment are located in active natural gas producing areas in central and eastern Oklahoma and are comprised of the assets we acquired through our purchase of ScissorTail on August 1, 2005. These assets include:


	•	3,364 miles of pipelines in eight primarily low-pressure gathering systems extending through counties encompassing an aggregate area of approximately 16,900 square miles, with combined throughput capacity of 231,000 Mcf/d as of September 30, 2006; and

	•	four processing plants, including the Southern Dome processing plant, with a combined inlet capacity of approximately 115,000 Mcf/d.

For the nine months ended September 30, 2006, average throughput volumes for our Mid-Continent Operations segment were 145,163 Mcf/d and average inlet volumes at our processing plants were65,761 Mcf/d. In addition to transportation of natural gas to our plants for processing, we deliver natural gas to three third-party plants, for which we receive a portion of the product revenues. Average daily throughput volumes processed at third-party plants for our Mid-Continent Operations were 34,759 Mcf/d for the nine months ended September 30, 2006.

Texas Gulf Coast Pipelines Segment. The assets comprising our Texas Gulf Coast Pipelines segment include 1,594 miles of pipelines with combined throughput capacity of 922,200 Mcf/d as of September 30, 2006, including 219,000 Mcf/d of throughput capacity on Webb Duval and are managed as four separate operating regions: the South Texas, Coastal Waters, Central Gulf Coast, and Upper Gulf Coast regions. For the nine months ended September 30, 2006, we averaged net throughput volume of 337,626 Mcf/d of natural gas through these pipeline assets.

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Texas Gulf Coast Processing Segment. The assets comprising our Texas Gulf Coast Processing segment include our Houston Central Processing Plant, our104-mile Sheridan NGL Pipeline and the46-mile Brenham NGL Pipeline that we lease from Kinder Morgan Energy Partners, LP. Our Houston Central Processing Plant, which has the capacity to process approximately 700,000 Mcf/d of natural gas, is the second largest natural gas processing plant in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. Our Houston Central Processing Plant removes NGLs from the natural gas supplied by the Kinder Morgan Texas Pipeline (KMTP)Laredo-to-Katy pipeline, which it straddles, and the pipelines in our Central Gulf Coast Region gathering systems. To the extent commercially desirable, these NGLs are separated into component NGL products at our Houston Central Processing Plant and are sold to third parties at the plant tailgate or transported for sale on our Sheridan NGL Pipeline and, beginning in early 2007, on our Brenham NGL Pipeline. For the nine months ended September 30, 2006, we averaged natural gas throughput volume of 487,469 Mcf/d through our Houston Central Processing Plant.

Mid-Continent Operations

On August 1, 2005, we completed the acquisition of ScissorTail. We refer to the business and properties of ScissorTail as our Mid-Continent Operations segment.

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The following map represents our Mid-Continent Operations segment:

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Our Mid-Continent Operations pipeline gathering systems include: Stroud, Osage, Milfay, Glenpool, Twin Rivers, Blue Mountain, Cyclone Mountain and Pine Mountain. The Paden, Glenpool and Milfay Processing Plants are integrated within the Stroud, Glenpool and Milfay Systems, respectively. We have set forth in the table below summary information describing the assets that comprise our Mid-Continent Operations segment:


					Nine Months Ended
					September 30, 2006
	Length		Existing Throughput		Average Throughput		Capacity
Gathering Pipelines	(Miles)		Capacity (Mcf/d)(2)		Volumes (Mcf/d)		Utilization

Stroud System		737		107,000		76,768		72	%
Osage System		549		24,000		17,820		74	%
Milfay System		372		15,000		12,396		83	%
Glenpool System		1,015		24,000		9,333		39	%
Twin Rivers System		527		16,000		11,206		70	%
Mountain Systems(1)		164		45,000		17,640		39	%

Total		3,364		231,000		145,163		63	%


			Nine Months Ended
			September 30, 2006
	Existing Throughput		Average Inlet		Capacity
Processing Plants	Capacity (Mcf/d)(2)		Volumes (Mcf/d)		Utilization

Paden		60,000		45,704		76	%
Milfay		15,000		11,366		76	%
Glenpool		25,000		8,691		35	%
Southern Dome(3)		15,000		1,229		8	%

Total		115,000		66,990		58	%


(1)		The Mountain Systems consist of three systems: Blue Mountain, Cyclone Mountain and Pine Mountain.

(2)		Many capacity values are based on current operating configurations and could be increased through additional compression, increased delivery meter capacityand/or other facility upgrades including, for example, larger dehydration capacity.

(3)		We hold a majority interest in Southern Dome, LLC, which owns the Southern Dome Processing Plant. The plant’s design capacity is 30,000 Mcf/d but is currently configured for an operating capacity of 15,000 Mcf/d.

Stroud System

The Stroud gathering system is comprised of approximately 737 miles of pipeline ranging from two inches to 12 inches in diameter. The Stroud System is located in Payne, Lincoln, Oklahoma, Pottawatomie, Seminole, and Okfuskee counties, Oklahoma. Average throughput for the nine month period ended September 30, 2006 was 76,768 Mcf/d. Approximately 27,283 Mcf/d of these volumes was delivered to a third-party processing plant and the remainder, approximately 49,484 Mcf/d, was delivered to our Paden Processing Plant. Approximately 474 active receipt meters currently are connected to the Stroud System.

The natural gas supplied to the Stroud System is generally under acreage dedication and long-term agreements with remaining terms ranging from two to approximately 14 years. Under an agreement with our largest producer, existing and future developments on 1.1 million acres in the Stroud system are dedicated to us through mid-year 2020. We also have dedications from additional producers covering production from an aggregate of over 250,000 acres pursuant to contracts ending between 2009 and 2011.

For the nine months ended September 30, 2006, 64.5% of the net average throughput volumes from the Stroud System was processed at our Paden Processing Plant. This plant is a turbo-expander cryogenic facility with current natural gas throughput capacity of approximately 60,000 Mcf/d. Placed into service in June 2001,

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the plant has the ability to reduce the ethane extracted from natural gas processed, or “reject ethane”. The ability to either retain ethane or reject it provides us with an advantage as ethane may be more valuable in liquid form (after extraction from natural gas) or retained within the gas stream, depending on market prices. For the nine months ended September 30, 2006, average inlet volumes were 45,704 Mcf/d and approximately 6,339 Bbls/d of raw mix NGLs were produced, together with approximately 35,485 MMBtu/d of residue gas and 495 Bbls/d of condensate. Because field compression provides the necessary pressure at the plant inlet, inlet compression is not required. The plant also has inlet condensate facilities including vapor recovery and a condensate stabilizer.

We are currently installing an additional 40,000 Mcf/d of plant refrigeration capacity at our Paden Processing Plant, which we expect to be operational in mid-2007. After this project is completed, the Paden Plant will have a total inlet processing capacity of 100,000 Mcf/d. In addition, our Board of Directors has approved a $9 million project to install a nitrogen rejection unit at the plant which, when completed, will allow us to remove unwanted nitrogen from the natural gas at the tailgate of the plant and ensure that gas from the expanded plant meets downstream pipeline specifications.

The residue natural gas from the Paden Processing Plant is delivered into Enogex’s natural gas transmission system for redelivery to Natural Gas Pipeline Company of America (“NGPL”) and CenterPoint and the NGLs are delivered to ONEOK Hydrocarbon, L.P. Due to increasing production volumes around the Paden Plant, the plant is expected to be operating at near full capacity by the end of 2007. The remaining throughput volumes from the Stroud System are processed at a third-party plant and we receive a share of the NGLs and residue gas. For the nine months ended September 30, 2006, our average daily inlet volumes processed at the third-party plant were 25,138 Mcf/d and approximately 2,851 Bbls/d of raw mix NGLs were produced, together with approximately 18,672 MMBtu/d of residue gas and 613 Bbls/d of condensate.

Osage System

The Osage gathering system is comprised of approximately 549 miles of pipeline ranging from two inches to eight inches in diameter. The Osage System is located in Osage, Pawnee, Payne, Washington and Tulsa counties, Oklahoma. Average throughput for the nine months ended September 30, 2006 was17,820 Mcf/d. Approximately 168 active receipt meters currently are connected to the Osage gathering system.

Given the lean nature of the wellhead production, the majority of the natural gas gathered on the Osage System is not processed. Downstream pipeline interconnects include Enogex, ONEOK Gas Transmission (“OGT”) and Keystone Gas. Gas that is delivered to Keystone Gas is processed by a third-party processor and we receive a share of the NGLs and residue gas. For the nine months ended September 30, 2006, our average daily inlet volumes processed at the third-party plant were 905 Mcf/d and approximately 99 Bbls/d of raw mix NGLs were produced, together with approximately 605 MMBtu/d of residue gas and 3 Bbls/d of condensate.

The primary producing areas that supply the Osage System are located in the southern part of the system. The area served by the Osage System is mature and current drilling activity is focused on the development of coalbed methane gas produced in the Rowe formation.

Milfay System

The Milfay gathering system is comprised of approximately 372 miles of pipeline ranging from two inches to eight inches in diameter. The Milfay System is located in Tulsa, Creek, Payne, Lincoln, and Okfuskee counties, Oklahoma. Average throughput for the nine months ended September 30, 2006 was 12,396 Mcf/d. Approximately 247 active receipt meters currently are connected to the Milfay System.

Substantially all of the gas from the Milfay System is delivered to our Milfay Processing Plant, which consists of a propane refrigeration facility with natural gas throughput capacity of approximately 15,000 Mcf/d. Average inlet volumes for the nine months ended September 30, 2006 were 11,366 Mcf/d and approximately 850 Bbls/d of raw mix NGL were produced, along with approximately 10,030 MMBtu/d of residue gas. Residue natural gas is delivered into OGT and the NGLs are delivered to ONEOK Hydrocarbon, L.P.

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Glenpool System

The Glenpool gathering system is comprised of approximately 1,015 miles of pipeline ranging from two inches to 10 inches in diameter. The Glenpool System is located in Tulsa, Wagoner, Muskogee, McIntosh, Okfuskee, Okmulgee and Creek counties, Oklahoma. Average throughput for the nine months ended September 30, 2006 was 9,333 Mcf/d. Approximately 429 active receipt meters currently are connected to the Glenpool System.

Substantially all of the gas from the Glenpool System is delivered to the Glenpool Processing Plant, which consists of a cryogenic facility with natural gas throughput capacity of approximately25,000 Mcf/d. Average inlet volumes for the nine months ended September 30, 2006 were 8,691 Mcf/d and approximately 554 Bbls/d of raw mix NGLs were produced, along with approximately 8,340 MMBtu/d of residue natural gas. Residue natural gas is delivered into either OGT or the American Electric Power Riverside Power Plant and the NGLs are delivered to ONEOK Hydrocarbon, L.P.

Twin Rivers System

The Twin Rivers gathering system is comprised of approximately 527 miles of pipeline ranging from two inches to 12 inches in diameter. The Twin Rivers System is located in Okfuskee, Seminole, Hughes, Pontotoc and Coal counties, Oklahoma. Average throughput for the nine month period ended September 30, 2006 was 11,206 Mcf/d. Approximately 298 active receipt meters currently are connected to the Twin Rivers System.

Substantially all of the system’s volumes are delivered to a third-party plant for processing and we receive a share of the NGLs and residue gas. Residue natural gas is delivered into Enogex’s natural gas transmission system for redelivery to CenterPoint and the NGLs are sold to Enogex. For the nine months ended September 30, 2006, our average daily inlet volumes processed at the third-party plant were 8,716 Mcf/d and approximately 780 Bbls/d of raw mix NGLs were produced, together with approximately 7,313 MMBtu/d of residue gas and 17 Bbls/d of condensate.

Mountain Systems

Our three Mountain Systems are located in the Arkoma Basin and include the Blue Mountain, Cyclone Mountain and Pine Mountain Systems. These systems comprise a total of approximately 164 miles of pipeline ranging from two inches to 20 inches in diameter. These systems are located in Atoka, Pittsburg and Latimer counties, Oklahoma. Average throughput for the nine month period ended September 30, 2006 was 17,640 Mcf/d. Approximately 137 active receipt meters currently are connected to the Mountain Systems.

Due to the lean nature of the wellhead production, natural gas gathered on our Mountain Systems does not require processing. Downstream pipeline interconnects include CenterPoint, Enogex and NGPL.

Southern Dome

As part of the ScissorTail Acquisition, we acquired a majority interest in Southern Dome, LLC, which was formed for the purpose of providing gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County. In April 2006, Southern Dome completed construction and began operation of its Southern Dome Processing Plant. The plant consists of a propane refrigeration facility with current natural gas throughput capacity of approximately 15,000 Mcf/d. Southern Dome also operates a3.4-mile gathering system, which is owned by a single producer. Substantially all of the gas from this gathering system is delivered to the Southern Dome Processing Plant. Southern Dome has signed a gas purchase and processing agreement with the producer, which runs through May 2025. Southern Dome receives a fee for operating the gathering system and a percentage of the producer’s natural gas and NGLs at the tailgate of the Southern Dome Plant.

Average inlet volumes for the nine months ended September 30, 2006 were 1,229 Mcf/d and approximately 58 Bbls/d of raw mix NGL were produced, along with approximately 1,010 MMBtu/d of residue gas. Residue natural gas is delivered into OGT.

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We are required to make 100% of the capital contributions required by Southern Dome until such time as its capital account balance equals 73% of the aggregate capital account balances of us and the other member. The maximum amount of capital contributions that we are obligated to make to Southern Dome is $18.3 million. Our total investment in Southern Dome as of September 30, 2006 is approximately $13.8 million. Additionally, prior to achieving “payout,” we are entitled to receive 69.5% of member distributions and, thereafter, to 50.1% of member distributions. Payout is achieved once we have received distributions equal to our capital contributions plus an 11% return. We are the managing member of Southern Dome and serve as its operator.

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Texas Gulf Coast Operations

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

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Texas Gulf Coast Pipelines Segment

We own approximately 1,594 miles of pipelines used for natural gas gathering and transmission, including approximately 144 miles of pipeline owned by Webb Duval. For the nine months ended September 30, 2006 and the year ended December 31, 2005, we averaged net throughput volumes of 337,626 Mcf/d and 321,600 Mcf/d, respectively, of natural gas. Our facilities are operated in four separate operating regions as described below.

We have set forth in the table below summary information describing our Texas Gulf Coast Pipelines Operations.


						Nine Months Ended
						September 30, 2006
				Existing		Net Average
				Throughput		Throughput
Texas Gulf Coast		Length		Capacity		Volumes		Capacity
Pipelines Operations	Pipeline Type	(Miles)		(Mcf/d)(1)		(Mcf/d)		Utilization

South Texas Region
Agua Dulce System(2)	Gathering and Transmission		442		98,000		21,635		22	%
Hebbronville System	Gathering		79		62,700		40,037		64	%
Karnes System	Gathering		103		17,500		6,496		37	%
Live Oak System	Gathering		142		106,600		21,125		20	%
Webb/Duval System(3)(4)	Gathering		144		219,000		101,848		47	%
Coastal Waters Region	Gathering		143		41,000		2,615		6	%
Central Gulf Coast Region	Gathering		311		239,000		114,308		48	%
Upper Gulf Coast Region	Gathering and Transmission		230		139,000		29,562		21	%

Total			1,594		922,800		337,626		37	%


(1)		Many capacity values are based on current operating configurations and circumstances and could be increased through additional compression, increased delivery meter capacityand/or other facility upgrades including, for example, larger dehydration capacity.

(2)		Throughput volumes presented in the table are net of intercompany transactions. Gross volumes and utilization of capacity in this area totaled 21,933 Mcf/d and 22%, respectively, for the nine months ended September 30, 2006.

(3)		Our Webb/Duval Area consists of the Webb/Duval Gathering System and two smaller gathering systems, which are owned by Webb Duval, an unconsolidated subsidiary in which we hold a 62.5% interest.

(4)		Throughput volumes presented in the table are net of affiliate transactions. Gross volumes and utilization of capacity in this area totaled 112,646 Mcf/d and 51%, respectively, for the nine months ended September 30, 2006.

South Texas Region

The South Texas Region consists of gathering and intrastate transmission systems totaling approximately 910 miles of pipelines operating in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces, Refugio and San Patricio Counties, Texas. This region is composed of five pipeline systems: the Agua Dulce System, the Hebbronville System, the Karnes System, the Live Oak System and the Webb/Duval System (in which we hold a 62.5% interest). This region is managed from our field office in Alice, Texas.

Agua Dulce System

Our Agua Dulce System consists of approximately 442 miles of pipeline assets ranging from two inches to 14 inches in diameter. Natural gas delivered to the Agua Dulce System is gathered from Duval, Jim Wells, Nueces and San Patricio Counties, Texas Natural gas is gathered and transported through the Agua Dulce System into the Webb/Duval Gathering System, which is then delivered to the KMTPLaredo-to-Katy pipeline

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for treating, conditioningand/or processing at our Houston Central Processing Plant. The Agua Dulce System has active interconnects with Houston Pipeline Company, NGPL, and Duke Energy Field Services and inactive interconnects with Enterprise Products Partners, L.P., Humble Gas Pipeline Company (an affiliate of ExxonMobil), and Duke Energy Field Services. Approximately 65 active receipt meters currently are connected to the Agua Dulce System.

Average net throughput volume on this system was 25,671 Mcf/d for the year ended December 31, 2005 and 21,635 Mcf/d for the nine months ended September 30, 2006.

Hebbronville System

Our Hebbronville System is comprised of approximately 79 miles of pipeline assets ranging from four inches to 16 inches in diameter and gathers natural gas from fields located in Duval and Jim Hogg Counties, Texas. All natural gas gathered from the Hebbronville System is transported for delivery to the KMTPLaredo-to-Katy Pipeline, which is then delivered to our Houston Central Processing Plant. Approximately 21 active receipt meters currently are connected to the Hebbronville System.

Average throughput volume on the Hebbronville System was 29,643 Mcf/d for the year ended December 31, 2005 and 40,037 Mcf/d for the nine months ended September 30, 2006.

Karnes System

The Karnes System is comprised of approximately 103 miles of pipeline assets ranging from four inches to 16 inches in diameter and gathers natural gas from fields located in Bee, DeWitt, Goliad, Karnes and Refugio Counties, Texas. Natural gas transported on the Karnes County Gathering System is either delivered to the KMTPLaredo-to-Katy pipeline for processing or conditioning at our Houston Central Processing Plant or is delivered into NGPL. Approximately 12 active receipt meters currently are connected to the Karnes System.

Average throughput volume on the Karnes System was 6,895 Mcf/d and 6,496 Mcf/d for the year ended December 31, 2005, and for the nine months ended September 30, 2006, respectively.

Live Oak System

Our Live Oak System is comprised of approximately 142 miles of pipeline ranging from two inches to 16 inches in diameter and gather natural gas from fields located in Atascosa, Live Oak and Duval Counties, Texas. Average throughput volume on this system was 18,286 Mcf/d for the year ended December 31, 2005 and 21,125 Mcf/d for the nine months ended September 30, 2006. Natural gas from the Live Oak System is delivered to the following locations: (1) the KMTPLaredo-to-Katy pipeline for treating, conditioningand/or processing at our Houston Central Processing Plant, (2) the Pueblo Midstream Fashing plant in Atascosa County, (3) Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.), or (4) NGPL.

Approximately 33 active receipt meters currently are connected to our Live Oak System.

Webb/Duval System

Our Webb/Duval System is a gathering system owned by Webb Duval, a general partnership that we operate and in which we hold a 62.5% interest. As the holder of a 62.5% interest in the partnership that owns this pipeline system, we operate this system subject to certain rights of the other partners, including the right to approve capital expenditures in excess of $0.1 million, financing arrangements by the partnership or any expansion projects associated with this system. In addition, each partner has the right to use its pro rata share of pipeline capacity on this system subject to applicable ratable take and common purchaser statutes.

The Webb/Duval System is a144-mile pipeline system located in Webb and Duval Counties, Texas, and is comprised of3-inch and16-inch diameter pipelines. Following our construction of a6-mile,12-inch diameter pipeline in 2002, the Webb/Duval Gathering System connects our Agua Dulce System to the KMTP

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Laredo-to-Katy pipeline. Approximately 27 active receipt meters currently are connected to the Webb/Duval Gathering System.

Average total throughput volume on this system including volumes delivered by our Agua Dulce System was 126,513 Mcf/d for the year ended December 31, 2005 and 112,646 Mcf/d for the nine months ended September 30, 2006. Excluding the volume received from our Agua Dulce System described previously, the average throughput volume on this system was 106,826 Mcf/d for the year ended December 31, 2005 and 101,848 Mcf/d for the nine months ended September 30, 2006.

Coastal Waters Region

The Coastal Waters Region is comprised of two pipeline systems, the Copano Bay System and the Encinal Channel System, consisting of approximately 143 miles of pipelines operating both onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. This region is managed from our field office in Lamar, Texas.

The Copano Bay System currently comprises approximately 120 miles of natural gas pipelines, which range in size from three inches to 12 inches in diameter. Currently, the Copano Bay System gathers natural gas from the offshore Matagorda Island Block 721 area, Aransas and Copano Bays, and adjacent onshore lands through Aransas Bay and onshore at Rockport, Texas. Natural gas and condensate are separated at our Lamar separation and dehydration facility, and the natural gas is delivered to an affiliate of Crosstex Energy, L.P. at Lamar, Texas. The condensate is stored and redelivered to producers and shippers who then truck the product to market. The Copano Bay System has 10 active receipt meters.

Average throughput volume on this system was 2,722 Mcf/d for the year ended December 31, 2005 and 2,615 Mcf/d for the nine months ended September 30, 2006.

The Encinal Channel Pipeline is an approximately23-mile pipeline that is currently inactive. The Encinal Channel Pipeline measures three inches to 12 inches in diameter and is located in Nueces and San Patricio Counties, Texas.

Central Gulf Coast Region

The Central Gulf Coast Region is composed of two intrastate natural gas gathering systems, the Sheridan System and the Provident City System, which consist of approximately 311 miles of pipeline and operate in Colorado, Dewitt, Lavaca, Victoria and Wharton Counties, Texas. This region is operated from our Houston Central Processing Plant located approximately 100 miles southwest of Houston. Interconnects at the tailgate of our Houston Central Processing Plant include KMTP, Tennessee Gas Pipeline, Texas Eastern Transmission and Houston Pipe Line Company.

The Sheridan System consists of approximately 60 miles of natural gas gathering lines ranging in size from four inches to 10 inches in diameter, and gathers natural gas from 23 active receipt meters and one third-party pipeline interconnect located in Colorado and Lavaca Counties, Texas. There is no installed compression or dehydration on this system. Natural gas from the Sheridan System is gathered and transported to our Houston Central Processing Plant for treatment of carbon dioxide, processing and ultimate delivery into the interconnects at the tailgate of our processing plant. The Sheridan System has a pipeline interconnect with the Enterprise Products Partners’ Chesterville System.

Average throughput volume on this system was 26,042 Mcf/d for the year ended December 31, 2005 and 29,186 Mcf/d for the nine months ended September 30, 2006.

The Provident City System consists of approximately 251 miles of natural gas gathering lines, ranging in size from two inches to 14 inches in diameter located in Colorado, DeWitt, Lavaca, Victoria and Wharton Counties, Texas and gathers natural gas from 94 active receipt meters and one third-party pipeline interconnect. The Provident City System has a pipeline interconnect with Duke Energy Field Services’ and Williams Energy Field Services.

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Average throughput volume on the Provident City System was 66,830 Mcf/d for the year ended December 31, 2005 and 85,122 Mcf/d for the nine months ended September 30, 2006.

Upper Gulf Coast Region

Our Upper Gulf Coast Region is composed of the Sam Houston System, the Grimes County System and the Lake Creek Pipeline, which consist of approximately 230 miles of pipeline used for gathering, transportation and sales of natural gas in Houston, Walker, Grimes, Montgomery and Harris Counties, Texas. This region is managed from our field office in Conroe, Texas.

The Sam Houston System includes approximately 125 miles of natural gas pipeline that gathers natural gas and receives natural gas from other pipelines for ultimate delivery to markets on the system. This gathering and transportation pipeline ranges in size from four inches to 12 inches in diameter. Approximately 17 active receipt meters currently are connected to the Sam Houston System.

The Sam Houston System has interconnects with Houston Pipe Line Company, Lone Star Pipeline Company, KMTP, Vantex Gas Pipeline Company and Texas Eastern Transmission. The Sam Houston System delivers natural gas to multiple CenterPoint Energy city gates in The Woodlands, Conroe and Huntsville, Texas, to Universal Natural Gas, a gas company providing services to residential markets in southern Montgomery County, Texas and to Entergy’s Lewis Creek Generating Plant and several industrial consumers.

Average net throughput volume on this system was 35,744 Mcf/d for the year ended December 31, 2005 and 26,061 Mcf/d for the nine months ended September 30, 2006.

The Grimes County System is an approximately77-mile natural gas gathering system located in Grimes County, Texas, which consists of natural gas pipelines ranging in size from two inches to 12 inches in diameter. We currently gather natural gas from 12 active receipt meters.

Average throughput volume on this system was 2,402 Mcf/d for the year ended December 31, 2005 and 1,610 Mcf/d for the nine months ended September 30, 2006.

The Lake Creek Pipeline is an approximately28-mile natural gas pipeline system located in Harris and Montgomery Counties, Texas. The Lake Creek Pipeline is comprised of6-inch and8-inch diameter natural gas pipelines. This pipeline has one receipt point and a bi-directional receipt and delivery point with Houston Pipe Line Company near the Bammel Storage field in Harris County. The majority of the natural gas transported on this pipeline is delivered to CenterPoint Energy at delivery points serving the western portion of The Woodlands, Texas and the surrounding area. Natural gas is also delivered to Universal Natural Gas.

Average throughput volume on this system was 539 Mcf/d for the year ended December 31, 2005 and 1,891 Mcf/d for the nine months ended September 30, 2006.

Texas Gulf Coast Processing Segment

The Texas Gulf Coast Processing assets include our Houston Central Processing Plant located near Sheridan, Texas in Colorado County, our Sheridan NGL Pipeline that runs from the tailgate of the processing plant to the Houston area and the Brenham NGL Pipeline.

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We have set forth in the table below summary information describing the assets comprising our Texas Gulf Coast Processing Operations.


						Nine Months Ended September 30, 2006
			Existing			NGLs		Average Inlet		Average
Texas Gulf Coast	Length		Throughput			Produced		Volumes		Throughput		Capacity
Processing Segment	(Miles)		Capacity			(Bbls/d)		(Mcf/d)		Volumes (Bbls/d)		Utilization

Houston Central Processing Plant		—		700,000 (Mcf/d	)		14,446		487,469		—		70	%
Sheridan NGL Pipeline(1)		104		18,900 (Bbls/d	)		—		—		12,090		60	%
Brenham NGL Pipeline(2)		46		—			—		—		N/A			N/A


(1)		Excludes throughput capacity for transportation of butadiene volumes. In October 2006 and pursuant to a contract with Texas Petrochemical Company, we began transporting small volumes of butadiene on a portion of our Sheridan NGL Pipeline that is not being used for transportation of NGLs from our Houston Central Processing Plant.

(2)		We expect to place the Brenham NGL Pipeline into service in early 2007.

Houston Central Processing Plant

Our Houston Central Processing Plant, which has approximately 700,000 Mcf/d of processing capacity, is the third largest in the state of Texas in terms of throughput capacity and the second largest and the most fuel efficient processing plant in the areas in which we operate. Our Houston Central Processing Plant removes NGLs from the natural gas supplied by the Kinder Morgan Texas Pipeline (KMTP)Laredo-to-Katy pipeline, which it straddles, and the pipelines in our Central Gulf Coast Region gathering systems. To the extent commercially desirable, these NGLs are separated into component NGL products at our Houston Central Processing Plant and are sold to third parties at the plant tailgate or transported for sale on our Sheridan NGL Pipeline and, beginning in early 2007, on our Brenham NGL Pipeline.

The Houston Central Processing Plant was originally constructed in 1965 by Shell and was comprised of a single refrigerated lean oil train and a fractionation facility. The plant was modified by Shell in 1985 with the addition of a second refrigerated lean oil train and in 1986 with the addition of a cryogenic turbo-expander train. This gas processing plant includes 6,689 horsepower of inlet compression, 8,400 horsepower of tailgate compression, a 700 gallon per minute amine treating system for removal of carbon dioxide and low-level hydrogen sulfide, two 250,000 Mcf/d refrigerated lean oil trains, one 200,000 Mcf/d cryogenic turbo-expander train, a 25,000 Bbls/d NGL fractionation facility, and 882,000 gallons of storage capacity for propane, butane and natural gasoline mix and stabilized condensate. We are currently expanding the amine treating system to 1,200 gallons per minute and the expansion is expected to be operational in the fourth quarter of 2006. The plant also has multiple tailgate interconnects for redelivery of natural gas with KMTP, Houston Pipe Line Company, Tennessee Gas Pipeline Company and Texas Eastern Transmission. In addition, at the tailgate of the plant, we operate our Sheridan NGL Pipeline and, beginning in early 2007, our Brenham NGL Pipeline, for transporting NGLs and TEPPCO operates an8-inch diameter crude oil and stabilized condensate pipeline that runs to refineries in the greater Houston area. In addition, we have an interconnect to an inactive6-inch diameter pipeline for transportation of ethane and propane operated by a subsidiary of Dow Chemical to Dow’s Freeport facility. Our Houston Central Processing Plant and related facilities are located on a163-acre tract of land, which we lease under three long-term lease agreements.

In 2003, we modified the processing plant to provide natural gas conditioning capability by installing two new 700 horsepower, electric-driven compressors to provide propane refrigeration through the lean oil portion of the plant, which enables us to shut down our steam-driven refrigeration compressor when we are conditioning natural gas. A third 700 horsepower electric-driven compressor has been installed and will be operational during the fourth quarter of 2006. These modifications provide us with the capability to process gas only to the extent required to meet pipeline hydrocarbon dew point specifications. Our ability to condition

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gas, rather than fully process it, provides us with significant benefits during periods when processing is not economic (when the price of natural gas is high compared to the price of NGLs), including:


	•	providing us with the ability to minimize the level of NGLs removed from the natural gas stream during periods when prices are high relative to NGL prices; and

	•	allowing us to operate our Houston Central Processing Plant more efficiently at a much reduced fuel consumption rate while still meeting downstream pipeline hydrocarbon dew point specifications.

As a result, during these periods the combination of reduced NGL removal and reduced fuel consumption at our plant allows us to preserve a greater portion of the value of the natural gas.

Our Houston Central Processing Plant has an inlet capacity of approximately 700,000 Mcf/d and had an average throughput of 530,346 Mcf/d for the year ended December 31, 2005 and an average throughput of 487,469 Mcf/d for the nine months ended September 30, 2006. The average volume of ethane and propane delivered from the plant to the Dow NGL pipeline was 8,697 Bbls/d for the year ended December 31, 2005 and 0 Bbls/d for the nine months ended September 30, 2006. The average volume of butane and NGLs delivered to the Sheridan NGL pipeline was 3,552 Bbls/d and 12,090 Bbls/d for the year ended December 31, 2005 and the nine months ended September 30, 2006, respectively. The average volume of stabilized condensate delivered from the plant to the TEPPCO crude oil pipeline was 808 Bbls/d for the year ended December 31, 2005 and 2,300 Bbls/d for the nine months ended September 30, 2006.

Sheridan NGL Pipeline

Our104-mile,6-inch diameter Sheridan NGL Pipeline originates at the tailgate of our Houston Central Processing Plant and currently delivers NGLs at a mid-line delivery point into the Enterprise Products Partners’ Seminole Pipeline for further transportation and fractionation. In October 2006 and pursuant to a contract with Texas Petrochemical Company, we began transporting small volumes of butadiene on a portion of our Sheridan NGL Pipeline that is not being used for transportation of NGLs from our Houston Central Processing Plant. Average throughput volume on this pipeline was 3,552 Bbls/d for the year ended December 31, 2005 and 12,090 Bbls/d for the nine months ended September 30, 2006.

Brenham NGL Pipeline

We lease a46-mile,6-inch diameter NGL pipeline from Kinder Morgan Energy Partners, L.P. under a5-year lease agreement dated February 1, 2006. This pipeline originates at the tailgate of our Houston Central Processing Plant and when operational in the first quarter of 2007, will deliver NGLs into the Enterprise Products Partners’ Seminole Pipeline near Brenham, Texas for ultimate redelivery for further transportation and fractionation.

Our Relationship With Kinder Morgan Texas Pipeline

KMTP is an intrastate natural gas pipeline system that is principally located in the Texas Gulf Coast region. KMTP transports natural gas from producing fields in South Texas, the Texas Gulf Coast and the Gulf of Mexico to markets in southeastern Texas. KMTP acts as a seller of natural gas as well as a transporter. We utilize KMTP as a transporter because our Houston Central Processing Plant straddles its30-inch diameterLaredo-to-Katy pipeline. By using KMTP as a transporter, we can transport natural gas from many of our pipeline systems to our processing plant and downstream markets. We refer to the natural gas delivered into KMTP’s pipeline from sources other than our gathering systems as “KMTP Gas.�� Under our contractual arrangement related to KMTP Gas, we receive natural gas at our plant, process or condition the natural gas and sell the NGLs to third parties at market prices. Because the extraction of NGLs from the natural gas stream during processing or conditioning reduces the British thermal units, or Btus, of the natural gas, our arrangement with KMTP requires us to purchase natural gas at market prices to replace the loss in Btus. Pursuant to an amendment to this contract with KMTP, effective February 1, 2006, we pay a fee to KMTP based on the NGL content of the KMTP Gas only during periods of favorable processing margins. In addition, the amendment provides that during periods of unfavorable processing margins, KMTP pays us the lesser of

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(i) the difference between the processing margin and a specified threshold or (ii) a fixed fee per Mcf of KMTP Gas. The amended processing agreement extends through January 30, 2011, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior written notice.

In connection with the execution of the amended processing agreement, we entered into a new five-year gas transportation agreement and a related gas sales agreement with KMTP, effective February 1, 2006. The new agreements eliminate the dedication of natural gas to KMTP from our individual gathering systems under previous purchase and sales agreements and allow for the aggregation of natural gas at the tailgate of the Houston Central Plant to meet our sales obligations to KMTP. Each of these agreements extends through January 31, 2011, with automatic annual renewals thereafter unless cancelled by either party upon 180 days’ prior written notice in the case of the gas transportation agreement or 30 days’ prior written notice in the case of the sales agreement.

For the nine months ended September 30, 2006, approximately 77% of the natural gas volumes processed or conditioned at our Houston Central Processing Plant were delivered to the plant through the KMTPLaredo-to-Katy pipeline while the remaining 23% was delivered directly into the plant from our gathering systems. Of the natural gas delivered into the plant from the KMTPLaredo-to-Katy pipeline, approximately 27% was delivered from gathering systems controlled by us and 73% was delivered into KMTP’s pipeline from other sources. Of the total volume of NGLs extracted at the plant during this period, 36% was attributable to KMTP Gas, while 64% was attributable to gas from gathering systems controlled by us, including our gathering systems connected directly to the plant.

Risk Management

We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps, and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives, and similar requirements. Our Risk Management Policy prohibits the use of derivative instruments for speculative purposes.

Commodity Price Risk

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is affected by prevailing commodity prices primarily as a result of two components of our business: (1) processing or conditioning at our processing plants or third-party processing plants and (2) purchasing and selling volumes of natural gas at index-related prices.

The processing contracts in our Mid-Continent Operations are predominantlypercentage-of-proceedsarrangements. Under these arrangements, we generally receive and process natural gas on behalf of producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase, and revenues and gross margins decrease as natural gas and NGL prices decrease.

The impacts of commodity prices on our Texas Gulf Coast Processing Operations are more complex, involving the interplay between our contractual arrangements and the ability of our Houston Central Processing Plant to eitherprocessorconditiongas depending on a price relationship known as theprocessing spreadorprocessing margin. Under those arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under a significant number of these arrangements, we also charge producers and third-party transporters a conditioning fee either at all times or only under certain conditions. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs results in a reduction in the Btus of the natural gas processed at our Houston Central Plant, which reduction is known as plant volume reduction, or PVR. When NGL prices are

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high relative to natural gas prices, theprocessing marginis said to be positive, and we operate our Houston Central Processing Plant in a manner intended to extract NGLs to the fullest extent possible. During such periods, we use a portion of the natural gas that we purchase from producers for the purpose of meeting our PVR requirements. Because of our contractual arrangements, operating our Houston Central Processing Plant in maximum recovery mode creates a long position in NGLs and a short position in natural gas. When processing margins are negative, we operate Houston Central Processing Plant inconditioning modeto extract the least amount of NGLs needed to meet downstream pipeline hydrocarbon dew point specifications. When we operate in a conditioning mode, the PVR requirements of our Houston Central Plant are significantly lower. The ability to condition rather than fully process natural gas provides an operational hedge that allows us to reduce our commodity price exposure. Accordingly, operating our Houston Central Processing Plant in conditioning mode reduces the long position in NGLs of our Texas Gulf Coast segments to nominal levels and eliminates our short position in natural gas for these segments on a combined basis.

Commodity Price Hedging Activities

We seek to mitigate the price risk of natural gas and NGLs through the use of commodity derivative instruments. These activities are governed by our Risk Management Policy, which allows management to:


	•	purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on West Texas Intermediate (“WTI”) crude oil;

	•	purchase put or call options, enter into collars (purchase of a put together with the sale of a call) or “call or put spreads” ((i) purchase of a call and a sale of a call at a higher strike price or (ii) purchase of a put and a sale of a put at a lower strike price)and/or sell fixed for floating swaps on natural gas at Henry Hub, Houston Ship Channel or other highly liquid points relevant to our operations;

	•	purchase put options, enter into collars or “put spreads”and/or sell fixed for floating swaps on natural gas liquids to which we, or an entity to be acquired by us, have direct price exposure, priced at Mt. Belvieu or Conway; and

	•	purchase put options and collarsand/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for any processing plant relevant to our operations or to the operations of an entity to be acquired by us.

Our policy also limits the maturity and notional amounts of our derivatives transactions and requires that:


	•	maturities with respect to the purchase of any hedge instruments must be limited to five years from the date of the transaction;

	•	notional volume must not exceed 80% of the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or natural gas liquids put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or natural gas liquids spread options; and

	•	the aggregate volumetric exposure associated with swaps, collars and written calls relating to any product must not exceed 50% of the aggregate hedged position with respect to such product.

Our policy of limiting swaps as a percentage of our overall hedge positions is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.

Our Risk Management Policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or withover-the-counter counterparties with investment grade ratings from both Moody’s and Standard & Poor’s with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first

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priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

We will seek, whenever possible, to enter into hedge transactions that meet or exceed the requirements for effective hedges as outlined in SFAS No. 133.

Mid-Continent Operations Segment. Natural gas for our Mid-Continent Operations segment is hedged using the CenterPoint East index, the principal index used to price the underlying commodity. With the exception of natural gasoline and condensate, NGLs are contractually priced using the Conway index, but since there is an extremely limited forward market for Conway, we use Mt. Belvieu hedge instruments instead. While this creates the potential for basis risk, statistical analysis reveals that the two indices are highly correlated.

Texas Gulf Coast Pipelines and Processing Segment. With the exception of natural gasoline and condensate, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. On November 21, 2006 we purchased natural gas call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central Processing Plant. The call spread options are based on the Houston Ship Channel Index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas Gulf Coast Pipelines and Processing segments because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central Processing Plant to switch between full recovery and conditioning mode. Because of our ability to reject ethane, we have not hedged our ethane production from our Texas Gulf Coast Processing segment.

Our Commodity Hedge Portfolio

The following table summarizes our commodity hedge portfolio as of November 21, 2006 (all hedges are settled monthly):

Purchased Houston Ship Channel Natural Gas Call Spreads as listed below:


	Call Strike
	(Per MMbtu)				Call Volumes
	bought		sold		(MMbtu/d)

2007	$	8.00	$	10.00		11,400
2008	$	8.15	$	10.00		9,400
2009	$	7.75	$	10.00		8,000
2010	$	7.35	$	10.00		7,100
2011	$	6.95	$	10.00		7,100

Purchased CenterPoint East Natural Gas Puts as listed below:


	Put Strike		Put Volumes
	(Per MMbtu)		(MMbtu/d)

2006	$	9.90		7,750
2007	$	8.75		9,750
2008	$	7.75		5,000
2009	$	6.95		5,000

Purchased Purity Ethane Puts and entered into swaps as listed below:


	Put Strike		Put Volumes		Swap Price		Swap Volumes
	(Per Gallon)		(Bbls/d)		(Per Gallon)		(Bbls/d)

2006	$	0.7125		568	$	0.7315		568
2007	$	0.6365		599	$	0.6525		599
2008	$	0.5700		607	$	0.5650		607

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Purchased TET Propane Puts and entered into swaps as listed below:


	Put Strike		Put Volumes		Swap Price		Swap Volumes
	(Per Gallon)		(Bbls/d)		(Per Gallon)		(Bbls/d)

2006	$	0.9525		2,508	$	1.0000		659
2007	$	0.8930		2,575	$	0.9375		726
2008	$	0.8360		2,594	$	0.8700		745

Purchased Non-TET Iso-Butane Puts and entered into swaps as listed below:


	Put Strike		Put Volumes		Swap price		Swap Volumes
	(Per Gallon)		(Bbls/d)		(Per Gallon)		(Bbls/d)

2006	$	1.1425		613	$	1.2050		83
2007	$	1.0675		620	$	1.1250		90
2008	$	0.9900		622	$	1.0450		92

Purchased Non-TET Normal-Butane Puts and entered into swaps as listed below:


	Put Strike		Put Volumes		Swap Price		Swap Volumes
	(Per Gallon)		(Bbls/d)		(Per Gallon)		(Bbls/d)

2006	$	1.1400		780	$	1.2000		241
2007	$	1.0650		803	$	1.1200		264
2008	$	0.9875		810	$	1.0400		271

Purchased WTI Crude Oil Puts as listed below:(1)


	Put Strike		Put Volumes
	(Per Barrel)		(Bbls/d)

2006	$	48.00		2,000
2007	$	48.00		2,000


(1)		WTI Crude Oil Puts were purchased in July 2005. Volumes are based on a30-day month.

Risk Management Oversight

Our Risk Management Committee is responsible for our compliance with our Risk Management Policy and is comprised of five officers of the company including the Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, the President of ScissorTail and the Vice President and General Counsel. The Audit Committee of our Board of Directors monitors the implementation of the policy, and we have engaged an independent firm to provide additional oversight.

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DIRECTORS AND OFFICERS

The following table shows information for our executive and operating officers and members of our board of directors. Executive officers and directors are elected for one-year terms.


Name	Age		Position with Our Company(1)

John R. Eckel, Jr.(2)		55	Chairman of the Board and Chief Executive Officer
R. Bruce Northcutt		47	President and Chief Operating Officer
Matthew J. Assiff		39	Senior Vice President and Chief Financial Officer
Ron W. Bopp		60	Senior Vice President, Corporate Development
Lari Paradee		43	Vice President and Controller
Douglas L. Lawing		45	Vice President, General Counsel and Secretary
Carl A. Luna		37	Vice President, Finance
Kathryn S. DeYoung		46	Vice President, Government and Regulatory Affairs
Wayne S. Harrison		57	Vice President and Chief Information Officer
Texas Gulf Coast Operations(1)
Brian D. Eckhart		51	Senior Vice President, Transportation and Supply
J. Terrell White		43	Vice President, Operations
James J. Gibson, III		60	Vice President, Processing
Mid-Continent Operations(1)
John R. Raber		52	President and Chief Operating Officer
Lee A. Fiegener		46	Vice President, Operations
Thomas A. Coleman		50	Vice President, Engineering
Bruce A. Roderick		48	Vice President, Accounting and Administration
Sharon J. Robinson		47	Vice President Commercial Activities
Non-Executive Board Members
James G. Crump(3)		66	Director
Ernie L. Danner(3)		52	Director
Scott A. Griffiths(3)		52	Director
Michael L. Johnson(3)		56	Director
T. William Porter(3)		65	Director
William L. Thacker(3)		61	Director


(1)		All officer positions are positions with Copano Energy, L.L.C. except those set forth under “Mid-Continent Operations,” which are positions with ScissorTail Energy, LLC, our indirect wholly-owned subsidiary.

(2)		Director since 1992.

(3)		Directors since 2004.

John R. Eckel, Jr., Chairman and Chief Executive Officer, founded our business in 1992 and served as our President and Chief Executive Officer until April 2003, when he was elected to his current position. Mr. Eckel serves on the Board of Directors and as Vice Chairman of the Texas Pipeline Association. Mr. Eckel also serves as President and Chief Executive Officer of Live Oak Reserves, Inc., which he founded in 1986, and which, with its affiliates, is engaged in oil and gas exploration and production in South Texas. Mr. Eckel received a Bachelor of Arts degree from Columbia University and was employed in various corporate finance positions in New York prior to entering the energy industry in 1979.

R. Bruce Northcutt, President and Chief Operating Officer, has served in his current capacity since April 2003. Mr. Northcutt served as President of El Paso Global Networks Company (a provider of wholesale bandwidth transport services) from November 2001 until April 2003, Managing Director of El Paso Global Networks Company from April 1999 until December 2001 and Vice President, Business Development, of

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El Paso Gas Services Company (a marketer of strategic interstate pipeline capacity) from January 1998 until April 1999. Mr. Northcutt began his career with Tenneco Oil Exploration and Production in 1982 working in the areas of drilling and production engineering. From 1988 until 1998, Mr. Northcutt held various levels of responsibility within several business units of El Paso Energy and its predecessor, Tenneco Energy, including supervision of pipeline supply and marketing as well as regulatory functions. Mr. Northcutt holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. Mr. Northcutt is a Registered Professional Engineer in Texas.

Matthew J. Assiff, Senior Vice President and Chief Financial Officer, has served in his current capacity since October 2004 and previously served as our Senior Vice President, Finance and Administration, from January 2002. Prior thereto, Mr. Assiff was a Vice President within the Global Energy Group of Credit Suisse and was with Donaldson, Lufkin and Jenrette (prior to its purchase by Credit Suisse in 2000) initially as an Associate and subsequently as a Vice President from 1998. Mr. Assiff began his career in 1989 with Goldman, Sachs & Co. in the Mergers & Acquisitions group focusing on energy transactions and has worked in the corporate finance and Mergers & Acquisition groups of Bear Stearns and Chemical Securities (now J. P. Morgan Chase). Mr. Assiff has also worked with Landmark Graphics Company and Compaq Computer in the areas of finance, planning, mergers and acquisitions and corporate venture investing. Mr. Assiff graduated from Columbia University with a Bachelor of Arts degree and holds a Masters of Business Administration degree from Harvard Business School.

Ron W. Bopp, Senior Vice President, Corporate Development, was elected to his current position in April 2005 to assist us with the development and management of our acquisition opportunities. Mr. Bopp served as Vice President — Onshore Assets of Shell US Gas & Power LLC, an affiliate of Shell Oil Company, from February 1998 until February 2005. From 1994 until February 1998, Mr. Bopp was Vice President and Chief Financial Officer of Corpus Christi Natural Gas Company, a midstream gas gathering, processing, and transportation company that was acquired by affiliates of Shell Oil Company in October 1997. Mr. Bopp graduated from the University of Houston with a Bachelor of Business Administration and a Master of Science in Accounting degree and is a Certified Public Accountant.

Lari Paradee, Vice President and Controller, has served in her current capacity since joining us in July 2003. As Vice President and Controller, Ms. Paradee is primarily responsible for our accounting and reporting functions. From September 2000 until March 2003, Ms. Paradee served as Accounting and Consolidations Manager for Intergen, a global power generation company jointly owned by Shell Generating (Holdings) B.V. and Bechtel Enterprises Energy B.V. Ms. Paradee served as Vice President and Controller of DeepTech International, Inc. (an offshore pipeline and exploration and production company) from May 1991 until August 1998, when DeepTech was merged into El Paso Energy Corporation. Ms. Paradee then served as Manager, Finance and Administration of El Paso Energy until March 2000. Ms. Paradee has served as Senior Auditor and Staff Auditor for Price Waterhouse. Ms. Paradee graduated magna cum laude from Texas Tech University with a B.B.A. in Accounting. Ms. Paradee is also a Certified Public Accountant.

Douglas L. Lawing, Vice President, General Counsel and Secretary, has served in his current capacity since October 2004 and previously served as our General Counsel since November 2003. From January 2002 until November 2003, Mr. Lawing served as our Corporate Counsel. Mr. Lawing has served as Corporate Secretary of our company and its predecessors since February 1994. Additionally, from March 1998 until January 2002, Mr. Lawing served as an Associate Counsel of Nabors Industries, Inc. (now Nabors Industries Ltd., a land drilling contractor). Mr. Lawing holds a Bachelor of Science degree in Business Administration from the University of North Carolina at Chapel Hill and a J.D. from Washington and Lee University.

Carl A. Luna, Vice President, Finance, has served in his current capacity since May 2006 and previously served us as a financial consultant from August 2005 to May 2006. Mr. Luna is primarily responsible for our finance and treasury functions. From 1997 until 2005, Mr. Luna served as a Vice President in the Syndicated and Leveraged Finance Group of J.P. Morgan Securities Inc. and as an Associate in that area from 1995 until 1997. Mr. Luna began his career at Texas Commerce Bank (now J.P. Morgan Chase Bank) in 1992 as an Analyst and subsequently as an Assistant Vice President in the Commercial Banking Division until 1995.

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Mr. Luna holds a Bachelor of Business Administration degree in Finance from Texas A&M University and a Master of Business Administration degree from Rice University.

Kathryn S. DeYoung, Vice President, Government and Regulatory Affairs, has served in her current capacity since March 2005. Ms. DeYoung is responsible for coordinating government affairs activities and compliance with state and federal regulations, including compliance with environmental, health and safety standards. Ms. DeYoung has been associated with us since our inception in 1992 and from August 2001 through February 2005, Ms. DeYoung served as our Senior Director, Operations Services. From June 1992 until August 2001, she served as our Director of Operations Services, where her duties included regulatory compliance and risk management. Ms. DeYoung attended the University of St. Thomas and the University of Houston.

Wayne S. Harrison, Vice President and Chief Information Officer, has served in his current capacity since joining our company in June 2005. From the company’s inception in 1992 until June 2005, Mr. Harrison served as a consultant to our company and in that capacity, developed and supported various accounting and financial software application systems. During this period, Mr. Harrison provided similar services to a number of other entities, including Tejas Gas, Energy Dynamics, and O’Connor-Braman Interests and also served as IT Manager for Berry Contracting from 1992 until May 2005. Mr. Harrison graduated from Del Mar College in Corpus Christi, Texas, with an Associate of Applied Science degree in Computer Science and attended Texas A&M University-Corpus Christi.

Brian D. Eckhart, Senior Vice President, Transportation and Supply, has served in his current capacity since March 2002. From January 1998 until March 2002, Mr. Eckhart served as our Vice President, Business Development. From February 1997 to January 1998, Mr. Eckhart served as Vice President, Operations. From 1979 until 1997, Mr. Eckhart held various engineering and management positions at Natural Gas Pipeline Company of America and other subsidiaries of MidCon Corporation, a predecessor of Kinder Morgan, Inc. Mr. Eckhart graduated from Texas A&M University with a Bachelor of Science degree in Ocean Engineering.

J. Terrell White, Vice President, Operations, has served in his current capacity since joining us in January 1998. Mr. White oversees pipeline operations, including new well connects, dehydration, compression, measurement, and construction activities. From 1990 until 1997, Mr. White served in increasingly responsible engineering, project management and business development roles with Enron Liquid Services Corp., and from February 1997 until January 1998 with TransCanada Energy USA, Inc., following its acquisition of certain Enron midstream assets. From 1985 until 1990, Mr. White was an engineer with Mobil E&P SE, Inc. and Mobil Chemical, involved primarily in gas processing, fractionation, gathering and NGL transportation. Mr. White is a Registered Professional Engineer in the State of Oklahoma. Mr. White graduated from the University of Alabama with a Bachelor of Science degree in Mechanical Engineering.

James J. Gibson, III, Vice President, Processing, has served in his current capacity since joining us in October 2001. Mr. Gibson oversees operations for our processing segment. From 1998 until September 2001, Mr. Gibson served as Manager, Business Development — Texas Gas Plants of Coral Energy, LLC, an affiliate of Shell Oil Company. From 1997 until 1998, Mr. Gibson served as Director, Gas Processing and Treating Services of Corpus Christi Natural Gas, Inc. From 1992 until 1997, Mr. Gibson was self-employed as a consultant to several midstream energy companies operating in Texas. From 1980 until 1992, Mr. Gibson served as Vice President — Plant Operations of Seagull Energy Corporation. From 1977 until 1980, Mr. Gibson served as project engineer for Houston Oil & Minerals Corporation. Mr. Gibson began his career in 1969 as an engineer with Sun Oil Company. Mr. Gibson is a Registered Professional Engineer in the State of Texas. Mr. Gibson graduated from Texas A&I University with a Bachelor of Science degree in Natural Gas Engineering.

John A. Raber, President and Chief Operating Officer — ScissorTail Energy, LLC, has served in his current capacity since ScissorTail was formed on July 1, 2000. Mr. Raber was also named President and Chief Operating Officer of Copano Rocky Mountains and Mid-Continent, LLC, our wholly-owned subsidiary, on August 1, 2005. Mr. Raber served as Vice President of Marketing and Business Development of Wyoming Refining Company (a Rocky Mountains refiner) from July 1999 to August 2005, Senior Vice President of Processing and other executive positions with Tejas Gas Corporation (a public midstream company) from

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February 1995 to July 1999 and as Vice President and other positions with LEDCO, Inc. (a private midstream and gas distribution company in Louisiana) from July 1982 to February 1995. Mr. Raber began his career as a Field and Operations Engineer with J. Ray McDermott, Inc. (a marine oil and gas construction company) working mainly in overseas locations from May 1976 to July 1982. Mr. Raber holds a Bachelor of Science degree in Civil Engineering from Tulane University and has also attended the Stanford Business School of Executive Education.

Lee R. Fiegener, Vice President, Field Operations — ScissorTail Energy, LLC, has served in his current capacity since June 2003. Mr. Fiegener joined ScissorTail Energy when it was formed and served as General Manager from July 2000 to June 2003. Prior to joining ScissorTail Energy, Mr. Fiegener served as District Manager for Enogex Inc., (a public midstream gathering, processing, and transmission company), from July 1999 to July 2000, and as Regional Manager and other positions with Transok, LLC (a public midstream gathering, processing and transmission company), from August 1982 to July 1999. Mr. Fiegener began his career with Transok, LLC in August 1982 as an Engine/Vibration Analyst. Mr. Fiegener holds a Bachelor of Science degree in Mechanical Engineering Technology from Oklahoma State University.

Thomas A. Coleman, Vice President, Engineering — ScissorTail Energy, LLC, joined the company in September 2000 as Manager of Engineering and was named Vice President in August 2005. Prior to joining ScissorTail, Mr. Coleman was a senior design engineer and project manager at Transok from July 1993 to December 1999. Mr. Coleman was employed at Willbros Engineers (a pipeline consulting company) from March 1989 to July 1993 and December 1999 to September 2000 as a project scheduler, field engineer and lead design engineer. Mr. Coleman began his career at Public Service Company of Oklahoma (electric utility company) and worked from 1982 to 1989 as a power plant performance engineer. Mr. Coleman earned a Bachelor of Science degree in Mechanical Engineering from the University of Tulsa in 1982 and is a Registered Professional Engineer in the State of Oklahoma.

Bruce A. Roderick, Vice President, Accounting and Administration — ScissorTail Energy, LLC, has served in his current capacity since ScissorTail was formed on July 1, 2000. Mr. Roderick served as Vice President, Accounting and Administration and other positions with Transok from April 1997 to September 1999. Mr. Roderick served as Director, Power Marketing for Central and Southwest Corporation (a public utility holding company) from March 1996 to April 1997. Mr. Roderick served Transok from February 1987 to March 1996 in leadership roles over Information Technology, Strategic Planning, Gas and Volume Control and Fuel Acquisition. Mr. Roderick began his career as a information technology consultant with Arthur Young & Company (a public accounting firm) from May 1980 to February 1987. Mr. Roderick holds a Bachelor of Science degree in Accounting from Oklahoma State University and is a Certified Public Accountant.

Sharon J. Robinson, Vice President, Commercial Activities — ScissorTail Energy, LLC, has served in her current capacity since June 2003. Ms. Robinson is responsible for overseeing the commercial operations, budgeting and business development activities for ScissorTail. Ms. Robinson joined ScissorTail when it was formed on July 1, 2000 and served as General Manager, Commercial from September 2001 to June 2003. Ms. Robinson worked for Transok, which later became Tejas Gas Corporation, from July 1993 through December 1999 in both commercial and engineering positions. Ms. Robinson began her career as a Project Engineer with Cities Service Oil Company, which later became Occidental Petroleum, in December 1981 and continued through March 1992. Ms. Robinson holds a Bachelor of Science in Chemical Engineering from Oklahoma State University and is a Registered Professional Engineer in the State of Oklahoma. Ms. Robinson also serves on the Board of Directors of the Gas Processors Association.

James G. Crumpjoined our Board of Directors upon completion of our initial public offering in November 2004. Mr. Crump is the Chairman of the Audit Committee and a member of the Conflicts Committee. He is also a member of the board of directors of UCO GP, LLC, the general partner of the general partner of Universal Compression Partners, L.P. Mr. Crump began his career at Price Waterhouse in 1962 and became a partner in 1974. From 1977 until the merger of Price Waterhouse and Coopers & Lybrand in 1998, Mr. Crump held numerous management and leadership roles. From 1998 until his retirement in 2001, Mr. Crump served as Global Energy and Mining Cluster Leader, a member of the U.S. Management

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Committee and the Global Management Committee and as Houston Office Managing Partner of PricewaterhouseCoopers. Mr. Crump holds a B.A. in Accounting from Lamar University.

Ernie L. Dannerjoined our Board of Directors upon completion of our initial public offering in November 2004. Mr. Danner is the Chairman of the Conflicts Committee and a member of the Audit Committee. Mr. Danner currently serves as Executive Vice President and Chief Operating Officer and as a director of Universal Compression Holdings Inc. Mr. Danner is also a member of the board of directors of UCO GP, LLC, the general partner of the general partner of Universal Compression Partners, L.P. Mr. Danner joined Universal Compression in 1998 as its Chief Financial Officer. He also serves as a director of Horizon Lines, Inc. Mr. Danner holds a B.A. and an M.A. in Accounting from Rice University.

Scott A. Griffithsjoined our Board of Directors in December 2004. Mr. Griffiths is a member of the Nominating and Governance Committee and the Compensation Committee. Mr. Griffiths served as Senior Vice President and Chief Operating Officer of Hydro Gulf of Mexico, L.L.C. from December 2005 to October 2006 and currently serves Hydro in an advisory capacity. From 2003 through December 2005, Mr. Griffiths served as Executive Vice President and Chief Operating Officer of Spinnaker Exploration Company. From 2002 to 2003, Mr. Griffiths served as Senior Vice President, Worldwide Exploration for Ocean Energy, Inc. Mr. Griffiths joined Ocean following the 1999 merger of Ocean and Seagull Energy Corporation, where he served as Vice President, Domestic Exploration. He holds a B.S. in Geology from the University of New Mexico and an M.A. in Geology from Indiana University.

Michael L. Johnsonjoined our Board of Directors in December 2004. Mr. Johnson is a member of the Audit Committee and the Conflicts Committee. Mr. Johnson began his career in 1975 with Conoco Inc. and most recently served as Chairman and Chief Executive Officer of Conoco Gas and Power from 1997 until his retirement in 2002. Mr. Johnson holds a B.S. in Geology from New Mexico State University, an M.A. in Geochemistry from Rice University and an M.S. in Management, Sloan Fellow from Alfred P. Sloan School of Business, M.I.T.

T. William Porterjoined our Board of Directors upon completion of our initial public offering in November 2004. Mr. Porter is the Chairman of the Nominating and Governance Committee and a member of the Compensation Committee. Mr. Porter is Chairman and a founding partner of Porter & Hedges, L.L.P., a Houston law firm formed in 1981. He also serves as a director of Cal Dive International, Inc. and as a director of U.S. Concrete, Inc. Mr. Porter holds a Bachelor of Business Administration degree in Finance from Southern Methodist University and Bachelor of Law degree from Duke University.

William L. Thackerjoined our Board of Directors upon completion of our initial public offering in November 2004. Mr. Thacker is the Chairman of the Compensation Committee and a member of the Nominating and Governance Committee. Mr. Thacker is a member of the board of directors of Kayne Anderson Energy Development Company and Mirant Corporation. Mr. Thacker joined Texas Eastern Products Pipeline Company (the general partner of TEPPCO Partners, L.P.) in September 1992 as President, Chief Operating Officer and director. He was elected Chief Executive Officer in January 1994. In March 1997, he was named to the additional position of Chairman of the Board, which he held until his retirement in May 2002. Prior to joining Texas Eastern Products Pipeline Company, Mr. Thacker was President of Unocal Pipeline Company from 1986 until 1992. Mr. Thacker is past Chairman of the Executive Committee of the Association of Oil Pipelines, has served as a member of the board of directors of the American Petroleum Institute, and has actively participated in many energy-related organizations during his35-year career in the energy industry. Mr. Thacker holds a Bachelor of Mechanical Engineering degree from the Georgia Institute of Technology and a Masters of Business Administration degree from Lamar University.

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TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of common units, please read “Material Tax Considerations” beginning on page 32 of the accompanying prospectus. You are urged to consult your own tax advisor about the federal, state, foreign and local tax consequences particular to your circumstances.

We estimate that if you purchase a common unit in this offering and hold the common unit through the record date for the distribution with respect to the fourth calendar quarter of 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for the taxable years 2006 through 2008 that will be less than 20% of the amount of cash distributed to you with respect to that period. This estimate is based upon many assumptions regarding our business and operations, including assumptions with respect to capital expenditures, cash flows and anticipated cash distributions. This estimate and our assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, this estimate is based on current tax law and tax reporting positions that we have adopted and with which the Internal Revenue Service might disagree. Accordingly, we cannot assure you that this estimate will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than our estimate, and any differences could materially affect the value of the common units. For example, the percentage of taxable income relative to our distributions could be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

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UNDERWRITING

UBS Securities LLC and Morgan Stanley & Co., Incorporated are acting as representatives of the underwriters and joint book-running managers for this offering. Under the terms of an underwriting agreement, which we will file as an exhibit to our Current Report onForm 8-K, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:


	Number of
Underwriters	Common Units

UBS Securities LLC		537,500
Morgan Stanley & Co., Incorporated		537,500
RBC Capital Markets Corporation		275,000
Lehman Brothers Inc.		275,000
Citigroup Global Markets Inc.		275,000
Wachovia Capital Markets, LLC		225,000
Banc of America Securities LLC		75,000
Deutsche Bank Securities Inc.		75,000
J.P. Morgan Securities Inc.		75,000
KeyBanc Capital Markets, a Division of McDonald Investments Inc.		75,000
Sanders Morris Harris Inc.		75,000

Total		2,500,000

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement including:


	•	the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units described below), if any of the common units are purchased;

	•	the representations and warranties made by us to the underwriters are true;

	•	there is no material change in the financial markets; and

	•	we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.


	No Exercise		Full Exercise

Per unit	$	2.51	$	2.51
Total	$	6,280,438	$	7,222,503

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus supplement and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $1.50 per unit. After the offering, the representatives may change the offering price and other selling terms.

We estimate that offering expenses will be approximately $0.7 million (exclusive of underwriting discounts and commissions).

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Option to Purchase Additional Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus supplement, to purchase, from time to time, in whole or in part, up to an aggregate of 375,000 common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 2,500,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this “Underwriting” section.

Lock-Up Agreements

We, our directors and certain executive officers or their affiliates have agreed that, without the prior written consent of UBS Securities LLC and Morgan Stanley & Co., Incorporated, we and they will not, directly or indirectly, (1) sell, offer to sell, contract or agree to sell, hypothecate, pledge, grant any option to purchase or otherwise dispose of or agree to dispose of or file a registration statement with the Securities and Exchange Commission (except as set forth below) in respect of, or establish or increase a put equivalent position or liquidate or decrease a call equivalent position with respect to any common units or any securities convertible into or exercisable or exchangeable for common units, including any subordinated units, or warrants or other rights to purchase common units or any such securities (other than (A) common units issued pursuant to employee benefit plans, qualified unit option plans or other employee compensation plans existing on the date of this prospectus supplement, (B) pledges existing on the date of this prospectus supplement, or (C) the issuance of employee unit options not exercisable during the lock-up period), (2) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of common units or (3) publicly announce an intention to effect any of the foregoing for a period of 90 days after the date of this prospectus supplement. Thelock-up period will be extended for up to 18 days under certain circumstances in which we release, or pre-announce a release of, our earnings results or where we disclose material news or a material event shortly before or after the termination of the90-day period. As an exception to the lock-up described above, certain of our executive officers will be entitled to sell or pledge up to an aggregate of (i) $500,000 worth of units to (A) satisfy tax liabilities associated with the vesting of awards under our equity compensation plan or (B) secure a loan for such purposes and (ii) $2.1 million worth of units to satisfy any tax liability associated with cash distributions on their units. In addition, in satisfaction of certain contractual obligations, we expect to file a shelf registration statement during the 90-day lock-up period described above, but the unitholders whose equity will be registered pursuant to that filing will be subject to a contractual lock-up for the remainder of such 90-day period.

UBS Securities LLC and Morgan Stanley & Co., Incorporated, in their discretion, may release the common units subject tolock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release common units fromlock-up agreements, UBS Securities LLC and Morgan Stanley & Co., Incorporated will consider, among other factors, the unitholders’ reasons for requesting the release, the number of common units for which the release is being requested, and market conditions at the time.

Certain of our institutional investors have the ability to sell their units under resale shelf registration statements that have been filed with the Securities and Exchange Commission and are currently effective. However, under the terms of the registration rights agreements governing their initial purchase of those units from us, the institutional investors have agreed not to sell common units covered by their registration statements for 30 days from the date we complete this offering.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, and to contribute to payments that the underwriters may be required to make for these liabilities.

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Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common unitsand/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the Nasdaq or otherwise and, if commenced, may be discontinued at any time. We have been advised by the underwriters that, prior to purchasing the common units being offered pursuant to this prospectus supplement, on November 30, 2006, one of the underwriters purchased, on behalf of the syndicate, 3,000 common units at an average price of $59.04 per unit in stabilizing transactions.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwritersand/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

S-45

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus supplement and the accompanying prospectus forms a part, has not been approvedand/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts without the prior specific written approval of the customer.

Relationships/ NASD Conduct Rules

An affiliate of Banc of America Securities LLC is the lender under our unsecured term loan and will receive greater than 10% of the net proceeds of this offering through our repayment of that facility. Affiliates of Banc of America Securities LLC, KeyBanc Capital Markets, a Division of McDonald Investments Inc., Deutsche Bank Securities Inc. and RBC Capital Market Corporation are lenders under our senior secured revolving credit facility and may be repaid with a portion of the net proceeds of this offering. In addition, affiliates of certain of the underwriters participating in this offering are counterparties with respect to our existing commodity hedge arrangements. Accordingly, this offering is being made in compliance with the requirements of Rule 2710(h) of the Conduct Rules of the National Association of Securities Dealers, Inc., or NASD. Pursuant to that rule, the appointment of a qualified independent underwriter is not necessary in connection with this offering as a bona fide independent market (as defined in the NASD Conduct Rules) exists in our common units.

Because the NASD views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD Conduct Rules.

Listing

Our common units are traded on the Nasdaq under the symbol “CPNO.”

LEGAL MATTERS

The validity of the common units offered hereby will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. performs legal services for us from time to time on matters unrelated to this offering.

EXPERTS

The consolidated financial statements and management’s report on the effectiveness of internal control over financial reporting of Copano Energy, L.L.C. incorporated in this prospectus by reference from the Company’s Annual Report onForm 10-K for the year ended December 31, 2005 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference (which reports (1) express an unqualified opinion on the consolidated financial statements and includes an explanatory paragraph related to, effective July 1, 2003, changes in accounting for financial instruments with characteristics of both liabilities and equity and, effective December 31, 2005, changes in accounting for conditional asset retirement obligations, (2) express an unqualified opinion on management’s assessment regarding the effectiveness of internal control over financial reporting, and (3) express an unqualified opinion on the effectiveness of internal control over financial reporting), and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

S-46

The financial statements of Webb Duval as of and for the year ended December 31, 2004 incorporated in this prospectus by reference from the Company’s Annual Report onForm 10-K for the year ended December 31, 2005 have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report, which is incorporated herein by reference, and have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of ScissorTail Energy, LLC as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004, incorporated in this prospectus supplement by reference from the current report onForm 8-K of Copano Energy, L.L.C. filed with the SEC on August 3, 2005, have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are incorporated by reference herein in reliance upon the authority of said firm as experts in auditing and accounting.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

Certain matters discussed in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference include “forward-looking” statements. Statements that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions, are forward-looking statements.

These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include statements related to plans for growth of the business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:


	•	our ability to successfully integrate any acquired assets or operations;

	•	the volatility of prices and market demand for natural gas and natural gas liquids;

	•	our ability to continue to obtain new sources of natural gas supply;

	•	the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;

	•	our ability to retain our key customers;

	•	general economic conditions;

	•	the effects of government regulations and policies; and

	•	other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (the “SEC”).

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this prospectus, including without limitation in conjunction with 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 in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference. All forward-looking statements included in those documents and all subsequent written or oral forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law.

S-47

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC under the Securities Act that registers the common units offered by this prospectus supplement. The registration statement, including the attached exhibits, contains additional relevant information about us. In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at1-800-732-0330 for further information on their public reference room. Our SEC filings are also available at the SEC’s web site at http://www.sec.gov. You can also obtain information about us at the offices of the Nasdaq, 20 Broad Street, New York, New York 10005.

The SEC allows us to incorporate by reference the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus supplement or the accompanying prospectus by referring you to those documents. The information incorporated by reference is an important part of this prospectus supplement and the accompanying prospectus. Information that we file (but not furnish) later with the SEC will automatically update and may replace information in this prospectus supplement and the accompanying prospectus and information previously filed with the SEC.

We incorporate the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (excluding any information furnished under Items 2.02 or 7.01 on any Current Report onForm 8-K) after the date of this prospectus supplement and until the termination of this offering. These reports contain important information about us, our financial condition and our results of operations.


	•	Our Annual Report onForm 10-K for the year ended December 31, 2005.

	•	Our Quarterly Reports onForm 10-Q for the quarterly periods ended March 31, 2006, June 30, 2006 and September 30, 2006.

	•	Our Current Reports onForm 8-K filed on August 3, 2005; January 3, 2006; January 19, 2006; January 20, 2006 (Items 8.01 and 9.01); February 3, 2006; February 8, 2006; February 21, 2006; April 6, 2006; April 7, 2006 (Item 1.01); April 19, 2006; May 30, 2006; June 1, 2006; July 20, 2006; October 5, 2006; October 19, 2006; November 20, 2006; November 22, 2006 and November 28, 2006.

	•	The description of our common units contained in our registration statement onForm 8-A, filed on November 1, 2004, and any subsequent amendment thereto filed for the purpose of updating such description.

You may obtain any of the documents incorporated by reference in this prospectus supplement and the accompanying prospectus from the SEC through the SEC’s web site at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus supplement and the accompanying prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at www.copanoenergy.com, or by writing or calling us at the following address:

Copano Energy, L.L.C.

Investor Relations

2727 Allen Parkway, Suite 1200

Houston, Texas 77019

(713) 621-9547

S-48

PROSPECTUS

COPANO ENERGY, L.L.C.
COPANO ENERGY FINANCE CORPORATION

Common Units
Debt Securities

We may offer, from time to time, in one or more series:


	•	common units representing limited liability company interests in Copano Energy, L.L.C.; and

	•	debt securities, which may be secured or unsecured senior debt securities or secured or unsecured subordinated debt securities.

Copano Energy Finance Corporation may act as co-issuer of the debt securities, and all other direct or indirect subsidiaries of Copano Energy, L.L.C., other than “minor” subsidiaries as such item is interpreted in securities regulation governing financial reporting for guarantors, may guarantee the debt securities.

Our common units are listed on the Nasdaq Global Select Market under the symbol “CPNO.” We will provide information in the prospectus supplement for the trading market, if any, for any debt securities we may offer.

We may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis. This prospectus describes the general terms of these securities. The specific terms of any securities and the specific manner in which we will offer them will be included in a supplement to this prospectus relating to that offering.

You should carefully read this prospectus and any prospectus supplement before you invest. You also should read the documents we have referred you to in the “Where You Can Find More Information” section of this prospectus for information on us and our financial statements. This prospectus may not be used to consummate sales of securities unless accompanied by a prospectus supplement.

Investing in our securities involves risks. In addition to risks related to our business, limited liability companies are inherently different from corporations. You should carefully consider the risk factors beginning on page 1 of this prospectus and in the applicable prospectus supplement before you make an investment in our securities.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is November 1, 2006.

TABLE OF CONTENTS


About this Prospectus			ii
Copano Energy, L.L.C.			ii
Risk Factors			1
Information Regarding Forward-Looking Statements			15
Use of Proceeds			16
Ratios of Earnings to Fixed Charges			16
Description of Our Common Units			16
Description of Our Debt Securities			19
Cash Distribution Policy			27
Material Tax Consequences			32
Legal Matters			46
Experts			46
Where You Can Find More Information			46

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, or the “SEC.” In making your investment decision, you should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus or any prospectus supplement or in the documents incorporated by reference into this prospectus or any prospectus supplement are accurate as of any date other than the date on the front cover of this prospectus or the date of such incorporated documents, as the case may be.

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we and Copano Energy Finance Corporation have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf process, we may sell the securities described in this prospectus in one or more offerings. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. That prospectus supplement may include additional risk factors or other special considerations applicable to those securities. Any prospectus supplement may also add, update, or change information in this prospectus. If there is any inconsistency between the information in this prospectus and any prospectus supplement, you should rely on the information in that prospectus supplement.

Additional information, including our financial statements and the notes thereto, is incorporated in this prospectus by reference to our reports filed with the SEC. Please read “Where You Can Find More Information.” You are urged to read this prospectus carefully, including the “Risk Factors,” and our SEC reports in their entirety before investing in our common units or debt securities.

Throughout this prospectus, when we use the terms “we,” “us,” “our,” or like terms, we are referring either to Copano Energy, L.L.C. or to Copano Energy, L.L.C. and its consolidated subsidiaries collectively, unless the context requires otherwise.

COPANO ENERGY, L.L.C.

We are a growth-oriented midstream energy company with natural gas gathering and intrastate transmission pipeline assets and natural gas processing facilities in the Texas Gulf Coast region and in central and eastern Oklahoma. Since our inception in 1992, we have grown through a combination of more than 30 acquisitions and construction of new assets. Our midstream assets include over 4,940 miles of natural gas gathering and transmission pipelines and five natural gas processing plants, with over 800 million cubic feet per day, or MMcf/d, of combined processing capacity. Our Houston Central Processing Plant is the second largest natural gas processing plant in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. This processing plant is located approximately 100 miles southwest of Houston and has the capacity to process approximately 700 MMcf/d of natural gas. In addition to our natural gas pipelines, we own the104-mile Sheridan NGL Pipeline extending from our Houston Central Processing Plant to the Houston area and we lease an additional47-mile NGL pipeline, which is expected to be operational in early 2007 and which extends from the tailgate of this processing plant to the Enterprise Product Partners’ Seminole Pipeline near Brenham, Texas. Our midstream assets include 144 miles of pipelines owned by Webb/Duval Gatherers (“Webb Duval”), a partnership in which we own a 62.5% interest and the Southern Dome processing plant owned by Southern Dome, LLC (“Southern Dome”), in which we own a 73% interest.

Copano Energy Finance Corporation, our wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto.

Our principal executive offices are located at 2727 Allen Parkway, Suite 1200, Houston, Texas 77019.

RISK FACTORS

You should carefully consider the following risk factors together with all of the other information included in this prospectus, any prospectus supplement and the information that we have incorporated herein by reference in evaluating an investment in Copano Energy, L.L.C. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. When we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement.

Risks Related to Our Business

If the ScissorTail Acquisition or future acquisitions do not perform as expected, our future financial performance may be negatively impacted.

Our acquisition of ScissorTail Energy, LLC (“ScissorTail”) in August 2005 (the “ScissorTail Acquisition”) more than doubled the size of our company and significantly diversified the geographic areas in which we operate. We cannot assure you that we will achieve the desired profitability from ScissorTail or any other acquisitions we may complete in the future. In addition, failure to successfully assimilate future acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions involve numerous risks, including:


	•	operating a significantly larger combined organization and adding operations;

	•	difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographic area;

	•	the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

	•	the loss of significant producers or markets or key employees from the acquired businesses;

	•	the diversion of management’s attention from other business concerns;

	•	the failure to realize expected profitability or growth;

	•	the failure to realize any expected synergies and cost savings;

	•	coordinating geographically disparate organizations, systems and facilities; and

	•	coordinating or consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

Our acquisition of ScissorTail could expose us to potential significant liabilities.

In connection with the ScissorTail Acquisition, we purchased all of the limited liability company interests of ScissorTail rather than just its assets. As a result, we purchased the liabilities of ScissorTail, including unknown and contingent liabilities. We performed due diligence in connection with the ScissorTail Acquisition and attempted to verify the representations of ScissorTail management, but there may be pending, threatened, contemplated or contingent claims against ScissorTail related to environmental, title, regulatory, litigation or other matters of which we are unaware. Although the former owners of ScissorTail agreed to indemnify us on a limited basis against some of these liabilities, a significant portion of these indemnification obligations expired on August 2, 2006 without any claims having been asserted by us. Accordingly, there is a risk that we could ultimately be liable for unknown obligations of ScissorTail, which could materially adversely affect our operations and financial condition.

Our substantial indebtedness could limit our operating flexibility and impair our ability to fulfill our debt obligations.

We have substantial indebtedness. As of September 30, 2006, we have:


	•	total indebtedness of approximately $375 million, including indebtedness associated with our outstanding 81/8% Senior Notes due 2016, our senior unsecured term loan and our senior secured revolving credit facility; and

	•	availability under our senior secured revolving credit facility of approximately $150 million.

Subject to the restrictions governing our existing indebtedness and other financial obligations, we may incur significant additional indebtedness and other financial obligations in the future. Our substantial indebtedness and other financial obligations could have important consequences to you. For example, it could:


	•	make it more difficult for us to satisfy our obligations with respect to our indebtedness;

	•	impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general company purposes or other purposes;

	•	result in higher interest expense in the event of increases in interest rates since some of our debt is, and will continue to be, at variable rates of interest;

	•	have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements and an event of default occurs as a result of that failure that is not cured or waived;

	•	require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general company requirements;

	•	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

	•	place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain such refinancing or equity capital or sell assets on satisfactory terms, if at all.

Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.

The indenture governing our outstanding senior notes contains various covenants that limit our ability and the ability of specified subsidiaries to, among other things:


	•	sell assets;

	•	pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt, if any;

	•	make investments;

	•	incur or guarantee additional indebtedness or issue preferred units;

	•	create or incur certain liens;

	•	enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

	•	consolidate, merge or transfer all or substantially all of our assets;

	•	engage in transactions with affiliates;

	•	create unrestricted subsidiaries; and

	•	enter into sale and leaseback transactions.

Our senior secured revolving credit facility and our senior unsecured term loan contain similar covenants as well as covenants that require us to maintain specified financial ratios and satisfy other financial conditions. These restrictive covenants in our indenture and in these credit facilities could limit our ability and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. We may be unable to comply with these covenants. Any future breach of any of these covenants could result in a default under the terms of the indenture, the senior secured revolving credit facility or the senior unsecured term loan, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against any collateral.

Our future success depends on our ability to continually obtain new sources of natural gas supply, and any decrease in supplies of natural gas could adversely affect our revenues and operating income.

Our gathering and transmission pipeline systems are connected to natural gas reserves and wells, for which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our pipeline systems and our processing plants, we must continually obtain new natural gas supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas and attract new customers to our gathering and transmission lines include: (1) the level of successful drilling activity near our gathering systems and (2) our ability to compete for the commitment of such additional volumes to our systems.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations, the amount of reserves underlying the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

We face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency, flexibility and reliability. Our major competitors for natural gas supplies and markets in our Texas Gulf Coast Pipelines segment include Enterprise Products Partners, L.P., Lobo Pipeline Company (an affiliate of ConocoPhillips), Kinder Morgan Texas Pipeline, L.P. (“KMTP,” an affiliate of Kinder Morgan Energy Partners, L.P.), Duke Energy Field Services, Crosstex Energy, L.P., and Houston Pipe Line Company, an affiliate of Energy Transfer Partners, L.P. Our Texas Gulf Coast Processing segment’s primary competitors are Enterprise Products Partners, L.P., ExxonMobil and Duke Energy Field Services. The primary competitors in our Mid-Continent Operations segment include CenterPoint, Duke Energy Field Services, Enogex Inc., an affiliate of OGE Energy Corp., and Enerfin Resources Company. Many of our competitors have greater financial resources than we have.

If we are unable to maintain or increase the throughput on our pipeline systems because of decreased drilling activity in the areas in which we operate, decreased production from the wells connected to our systems or an inability to connect new supplies of gas and attract new customers to our gathering and transmission lines, then our business and financial results or our ability to achieve our growth strategy could be materially adversely affected.

If KMTP’sLaredo-to-Katy pipeline becomes unavailable to transport natural gas to or from our Houston Central Processing Plant for any reason, then our cash flow and revenue could be adversely affected.

Our ability to contract for natural gas supplies in the Texas Gulf Coast region will often depend on our ability to deliver gas to our Houston Central Processing Plant and downstream markets. If we are unable to

deliver natural gas to this processing plant or to downstream markets, then our ability to contract for natural gas supplies could be hindered, and our cash flow and revenue would likely be adversely affected. For the year ended December 31, 2005, approximately 51% of the total natural gas delivered by our Texas Gulf Coast pipelines was delivered to KMTP. We deliver this natural gas to KMTP in order to transport it to our Houston Central Processing Plant, which straddles KMTP’sLaredo-to-Katy pipeline. Depending on the supply of residue gas at our processing plant and natural gas market conditions, we may sell natural gas to KMTP or to other shippers that transport natural gas through KMTP’sLaredo-to-Katy pipeline. Additionally, we may use KMTP’sLaredo-to-Katy pipeline to transport natural gas to our pipelines located in the Upper Gulf Coast Region of our Texas Gulf Coast Pipelines segment and to downstream markets.

If KMTP’s pipeline were to become unavailable for any reason, the volumes transported to our Houston Central Processing Plant would be reduced substantially, and our cash flows and revenues from our processing business could be adversely affected. In addition, many producers that use our Texas Gulf Coast gathering systems have natural gas containing NGLs that must be conditioned or processed in order to meet downstream market quality specifications. If we were unable to ship such natural gas to our Houston Central Processing Plant for processing or conditioning, and, if required, treating, we would need to arrange for transportation through other pipelines that could provide these services. Alternatively, we might be required to lease smaller conditioning, and possibly treating, facilities in order to deliver natural gas to other pipelines having restrictive natural gas quality specifications.

We generally do not obtain independent evaluations of natural gas reserves dedicated to our pipeline systems; therefore, volumes of natural gas transported on our pipeline systems in the future could be less than we anticipate, which may cause our revenues and operating income to be less than we expect.

We generally do not obtain independent evaluations of natural gas reserves connected to our pipeline systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our pipeline systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas transported on our pipelines in the future could be less than we anticipate. A decline in the volumes of natural gas transported on our pipeline systems may cause our revenues to be less than we expect.

We are exposed to the credit risk of our customers and counterparties, and a general increase in the nonpayment and nonperformance by our customers could have an adverse impact on our financial condition and results of operations.

Risks of nonpayment and nonperformance by our customers are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could have an adverse impact on our operating results and could adversely impact our liquidity.

Our profitability depends upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.

Our profitability is affected by prevailing NGL and natural gas prices and we are subject to significant risks due to fluctuations in commodity prices. These risks are based primarily upon two components of our business: (1) processing or conditioning at our processing plants, and (2) purchasing and selling volumes of natural gas at index-related prices.

The profitability of our Texas Gulf Coast Processing segment is affected by the relationship between natural gas prices and NGL prices. When natural gas prices are low relative to NGL prices, it is more profitable for us to process the natural gas than to condition it. When natural gas prices are high relative to NGL prices, we have the flexibility to condition natural gas at the Houston Central Processing Plant rather than fully process it, but the resulting margins are less. Accordingly, if natural gas prices remain high relative to NGL prices for extended periods of time, then our results of operations could be adversely impacted.

The margins we realize from purchasing and selling a portion of the natural gas that we deliver through our Texas Gulf Coast Pipeline systems decrease in periods of low natural gas prices because such gross margins are based primarily on a percentage of the index price. For the year ended December 31, 2005, approximately 96% of the natural gas purchased by our Texas Gulf Coast Pipelines segment was purchased with a percentage of relevant index pricing component. Accordingly, a decline in the price of natural gas could have an adverse impact on the results of operations from our Texas Gulf Coast Pipelines business.

The profitability of our Mid-Continent Operations segment is affected primarily by the level of NGL and natural gas prices. Because we generally receive a percentage of the sales proceeds of any NGLs extracted from the natural gas we gather in our Mid-Continent Operations segment as well as a percentage of the sales proceeds of the residue gas remaining after the NGL extraction, our Mid-Continent Operations segment’s profitability increases with higher commodity prices and decreases with a fall in commodity prices.

We will seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations. However, we may not be successful in balancing our natural gas purchases and sales. In addition, a producer could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a consumer could take more or less than contracted volumes. Any of these actions could cause an imbalance in our natural gas purchases and sales. If our purchases and sales of natural gas are not balanced, we will face increased exposure to commodity price risks, which could increase the volatility of our operating income.

The markets and prices for natural gas and NGLs depend upon many factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:


	•	the impact of weather on the demand for oil and natural gas;

	•	the level of domestic oil and natural gas production;

	•	the availability of imported oil and natural gas;

	•	actions taken by foreign oil and gas producing nations;

	•	the availability of local, intrastate and interstate transportation systems;

	•	the availability and marketing of competitive fuels;

	•	the impact of energy conservation efforts; and

	•	the extent of governmental regulation and taxation.

A change in the characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Most of our Texas pipelines are gathering systems that have been deemed non-utilities by the Railroad Commission of Texas, or TRRC. Through the ScissorTail Acquisition, we acquired gathering systems in Oklahoma that are not subject to utility regulation by the Oklahoma Corporation Commission, or OCC. Under Texas law, non-utilities in Texas are not subject to general rate regulation by the TRRC. Under Oklahoma law, non-utilities in Oklahoma (such as ScissorTail’s gathering systems) are not subject to general rate regulation

by the OCC. Should the status of these non-utility assets change, they would become subject to general rate regulation by the TRRC or OCC, which could adversely affect the rates that we are allowed to charge our customers. Some of our intrastate natural gas transmission pipelines are subject to regulation as a common purchaser and as a gas utility by the TRRC. The TRRC’s jurisdiction over these pipelines extends to both rates and pipeline safety. The rates we charge for transportation services in Texas are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business could be adversely affected.

As a natural gas gatherer and intrastate pipeline company, we are exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, but FERC regulation still affects our business and the market for our products. FERC’s policies and practices across the range of its natural gas pipeline regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the rates, terms and conditions of some of the transportation services we provide on our pipelines are subject to FERC regulation under Section 311 of the Natural Gas Policy Act.

Other state and local regulations also affect our business. Our gathering lines in Texas are subject to ratable take and common purchaser statutes. The gathering facilities we acquired in the ScissorTail Acquisition are likewise subject to ratable take and common purchaser statutes in Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. Texas and Oklahoma have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

Compliance with pipeline integrity regulations issued by the TRRC and OCC could result in substantial expenditures for testing, repairs and replacement.

The TRRC and OCC regulations require periodic testing of all intrastate pipelines meeting certain size and location requirements. Our costs relating to compliance with the required testing and repairs under the TRRC regulations was $0.8 million and $1.1 million for year ended December 31, 2005 and the nine months ended September 30, 2006, respectively. No costs were incurred relating to the pipeline integrity testing requirements of the OCC for the year ended December 31, 2005 or for the nine months ended September 30, 2006. If our pipelines fail to meet the safety standards mandated by the TRRC or OCC regulations, then we may be required to repair or replace sections of such pipelines, the cost of which cannot be estimated at this time.

Because we handle natural gas and other petroleum products in our pipeline and processing businesses, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operation of our gathering systems, plants and other facilities is subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain

environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of substances into the environment, and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

Expanding our business by constructing new assets will subject us to risks that projects may not be completed on schedule, the costs associated with the projects may exceed our expectations and additional natural gas supplies may not be available following completion of the projects, which could cause our revenues to be less than anticipated. Our operating cash flows from our capital projects may not be immediate.

One of the ways we may grow our business is through the construction of additions to our existing gathering and transportation systems (including additional compression) and modifications at our existing processing plants. The construction of additions or modifications to our existing gathering and transportation systems and processing and treating facilities, and the construction of new gathering and processing facilities, involve numerous regulatory, environmental, political, legal and operational uncertainties beyond our control and require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, Southern Dome, our non-wholly-owned operating subsidiary, has constructed a processing plant and pipelines to support anticipated future production in Oklahoma County, Oklahoma, which were placed in service on April 28, 2006. The cost of the project was born by us and the other member of Southern Dome, with our share of the final construction costs totaling approximately $18.0 million. The development of production dedicated to the Southern Dome processing plant and pipelines may occur over an extended period of time, and we may not receive any material increase in operating cash flow from that project for some time. If we experience unanticipated or extended delays in generating operating cash flow from this or other projects, then we may need to reduce or reprioritize our capital budget to meet our capital requirements. We may also rely on estimates of future production in our decision to construct additions to our gathering and transportation systems, which may prove to be inaccurate because of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return.

If the cost of renewing existingrights-of-way increases, it may have an adverse impact on our profitability. In addition, if we are unable to obtain newrights-of-way, then we may be unable to fully execute our growth strategy.

The construction of additions to our existing gathering and transportation assets may require us to obtain newrights-of-way prior to constructing new pipelines. We may be unable to obtain suchrights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain newrights-of-way or to renew existingrights-of-way. If the cost of renewing existingrights-of-way increases then our results of operations could be adversely affected. In addition, increasedrights-of-way costs could impair our ability to grow.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

Our operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:


	•	damage to pipelines, pipeline blockages and damage to related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters and acts of terrorism;

	•	inadvertent damage from construction and farm equipment;

	•	leaks of natural gas, NGLs and other hydrocarbons;

	•	operator error; and

	•	fires and explosions.

These risks could result in substantial losses due to personal injuryand/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. In addition, mechanical malfunctions, undetected ruptures in pipelines, faulty measurement or other errors may result in significant costs or lost revenues. Our operations are primarily concentrated in the Texas Gulf Coast region and in central and eastern Oklahoma, and a natural disaster or other hazard affecting any of these areas could have a material adverse effect on our operations. For example, although we did not suffer significant damage, Hurricane Katrina and Hurricane Rita damaged gathering systems, processing facilities, and NGL fractionators along the Gulf Coast in August and September 2005, respectively, which curtailed or suspended the operations of various energy companies with assets in the region. There can be no assurance that insurance will cover all damages and losses resulting from these types of natural disasters. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. Our business interruption insurance covers only losses arising from physical damage to our Houston Central Processing Plant, our Copano Bay pipeline system, our Paden Plant and other systems without alternative interconnects. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

Due to our lack of asset diversification, adverse developments in our gathering, transportation, processing and related businesses would have a significant impact on our results of operations.

Substantially all of our revenues are generated from our gathering, dehydration, treating, conditioning, processing and transportation businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Furthermore, substantially all of our assets are located in Texas and Oklahoma. Due to our lack of diversification in asset type and location, an adverse development in one of these businesses or in these areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

If we fail to maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results or prevent fraud. As a result, we may experience materially higher compliance costs.

In early 2005, we began a process to annually document and evaluate our internal control over financial reporting in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related regulations, which require annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent registered public accounting firm addressing these assessments. In this regard, management has dedicated internal resources, engaged outside consultants and

adopted a detailed work plan to (i) assess and document the adequacy of our internal control over financial reporting, (ii) take steps to improve control processes, where appropriate, (iii) validate through testing that controls are functioning as documented and (iv) implement a continuous review and reporting process for internal control over financial reporting. Our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and the related regulations regarding our assessment of our internal control over financial reporting and our independent registered public accounting firm’s audit of that assessment have resulted, and are likely to continue to result, in increased expenses. We cannot be certain that these measures will ensure that we maintain adequate controls over our financial processes and reporting in the future. Any failure to implement required new controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations. If compliance with policies or procedures deteriorate and we fail to correct any associated issues in the design or operating effectiveness of our internal control over financial reporting or fail to prevent fraud, current and potential holders of our securities could lose confidence in our financial reporting, which could harm our business.

Risks Related to Our Structure

Our limited liability company agreement prohibits a unitholder who acquires 15% or more of our common units without the approval of our board of directors from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Laws, or the DGCL. Section 203 of the DGCL as it applies to us prevents an interested unitholder, defined as a person who owns 15% or more of our outstanding units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for our common units.

Our cap on certain general and administrative expenses expires on December 31, 2007 (if not extended by our pre-IPO investors). Once the cap expires, our pre-IPO investors will no longer be required to reimburse us for certain amounts in excess of the cap, which could materially reduce the cash available for distribution to our unitholders.

Pursuant to our limited liability company agreement, for three years beginning on January 1, 2005, our pre-IPO investors agreed to reimburse us for our general and administrative expenses in excess of the following levels (subject to certain limitations):


	General and Administrative
Year	Expense Limitation

1	$	1.50 million per quarter
2	$	1.65 million per quarter
3	$	1.80 million per quarter

During this three-year period, the limitation on general and administrative expenses for any quarter will be increased by 10% of the amount by which EBITDA for that quarter exceeds $5.4 million. This limitation, or 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.

Once the cap expires, our pre-IPO investors will no longer be required to reimburse us for certain amounts in excess of the cap. As a result, all of our general and administrative expenses will be paid by us, which could materially reduce the cash available for distributions to our unitholders. For a detailed discussion of our cap on general and administrative expenses, please read “Item 7. Management’s Discussion and

Analysis of Financial Condition and Results of Operation — How We Evaluate Our Operations — General and Administrative Expenses” included in our Annual Report onForm 10-K for the year ended December 31, 2005, which is incorporated by reference into this prospectus.

Distributions to our pre-IPO investors may be insufficient to allow them to reimburse us for all of our general and administrative expenses in excess of the cap, which could materially reduce the cash available for distributions to our unitholders.

Our pre-IPO investors have agreed to reimburse us on a quarterly basis for our general and administrative expenses in excess of stated levels for a period of three years beginning on January 1, 2005, subject to certain limitations. Pursuant to our limited liability company agreement, these reimbursement obligations are currently limited solely to the amount of distributions attributable to the 5,557,378 common and subordinated units owned by our pre-IPO investors immediately prior to our initial public offering. Based on our current quarterly distribution rate of $0.75 per unit, these distributions would total, in the aggregate, $4.2 million quarterly and $16.7 million annually. If the distributions attributable to the common and subordinated units held by our pre-IPO investors immediately prior to our initial public offering are insufficient to reimburse us for all of the excess general and administrative expense, then amounts not reimbursed will be paid by us, which could have a material adverse effect on the cash available for distribution to our unitholders.

We may issue additional common units without your approval, which would dilute your existing ownership interests.

During the subordination period (as described in “Cash Distribution Policy — Subordination Period”), we may issue up to 3,519,126 additional common units without your approval. We may also issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without your approval, in a number of circumstances, such as:


	•	the issuance of common units in connection with acquisitions or capital improvements that our management determines would increase cash flow from operations per unit on an estimated pro forma basis;

	•	issuances of common units to repay certain indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with the debt’s retirement;

	•	the conversion of subordinated units into common units;

	•	the conversion of units of equal rank with the common units into common units under some circumstances;

	•	the issuance of common units under our long-term incentive plan; or

	•	the redemption of common units with the proceeds of a concurrent offering of common units.

After the end of the subordination period, we may issue an unlimited number of limited liability company interests of any type, including common units, without the approval of our unitholders. Our limited liability company agreement does not give the unitholders the right to approve our issuance at any time of equity securities ranking junior to the common units.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	your proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution during the subordination period will be borne by the common unitholders will increase;


	•	the relative voting strength of each previously outstanding unit will be diminished; and

	•	the market price of the common units may decline.

Our limited liability company agreement provides for a limited call right that may require you to sell your common units at an undesirable time or price.

If, at any time, any person owns more than 90% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your units.

Certain of our investors may sell units in the public market, which could reduce the market price of our outstanding common units.

Pursuant to our limited liability company agreement and the Stakeholder’s Agreement dated July 30, 2004 among us and our pre-IPO investors, we agreed to register for sale units received by affiliates of our management, Credit Suisse and EnCap Investments in connection with our initial public offering, including 2,038,252 common units received upon the closing of the IPO and 3,519,125 common units to be issued upon the conversion of our subordinated units. Each subordinated unit will convert into one common unit at the end of the subordination period, which may be as early as the first quarter of 2007. For a more detailed description of the circumstances under which the subordinated units will convert into common units, please read “Description of Our Common Units — Conversion of the Subordinated Units.” We have also registered (i) 6,203,216 common units issued to private investors in connection with the ScissorTail Acquisition and (ii) 1,418,440 common units issued to private investors in December 2005 and January 2006. Pursuant to these obligations, we registered an aggregate of 7,260,908 of these common units under a registration statement onForm S-3, which was declared effective by the Securities and Exchange Commission on January 26, 2006. Additionally, we have registered an additional 1,418,440 common units under a registration statement onForm S-3, which was declared effective by the SEC on April 28, 2006. If investors holding these units were to dispose of a substantial portion of their units in the public market, it could temporarily reduce the market price of our outstanding common units.

Risks Related to the Debt Securities

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the limited liability company interests and other equity interests in our subsidiaries. As a result, our ability to make required payments on our outstanding senior notes or any future issuances of debt securities will depend on the performance of our subsidiaries and their ability to distribute funds to us. The ability of the subsidiaries to make distributions to us may be restricted by, among other things, applicable state laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our outstanding senior notes or any future issuance of debt securities, or to repurchase our outstanding senior notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of our outstanding senior notes or any future issuance of debt securities. We cannot assure you that we would be able to refinance our outstanding senior notes or any future issuance of debt securities.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, including our outstanding senior notes and any future issuance of debt securities, and to fund planned capital expenditures depends on our

ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under the senior secured revolving credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness, including our outstanding senior notes and any future issuance of debt securities, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including our outstanding senior notes and any future issuance of debt securities, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our outstanding senior notes and any future issuances of debt securities, on commercially reasonable terms or at all.

We do not have the same flexibility as other types of organizations to accumulate cash which may limit cash available to service our outstanding senior notes or any future issuances of debt securities or to repay them at maturity.

Subject to the limitations on restricted payments contained in the indenture governing our outstanding senior notes and in our senior secured revolving credit facility and any other indebtedness, we distribute all of our “available cash” each quarter to our unitholders. “Available cash” is defined in our limited liability company agreement, and it generally means, for each fiscal quarter:


	•	all cash on hand at the end of the quarter;

	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Our credit facility does not provide for the type of working capital borrowing that would be eligible, pursuant to our limited liability company agreement, to be considered available cash.

	•	less the amount of cash that our board of directors determines in its reasonable discretion is necessary or appropriate to:


	•	provide for the proper conduct of our business (including reserves for future capital expenditures and for our future credit needs);

	•	comply with applicable law, any of our debt instruments, or other agreements or obligations; or

	•	provide funds for distributions to our unitholders for any one or more of the next four quarters.

As a result, we may not accumulate significant amounts of cash. If our board of directors fails to establish sufficient reserves, these distributions could significantly reduce the cash available to us in subsequent periods to make payments on our outstanding senior notes and any future issuance of debt securities.

The guarantees by certain of our subsidiaries of our outstanding senior notes and any future issuances of debt securities could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void these subsidiary guarantees.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under a guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:


	•	intended to hinder, delay or defraud any present or future creditor or received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee;

	•	was insolvent or rendered insolvent by reason of such incurrence;

	•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

	•	intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

In addition, any payment by that guarantor under a guarantee could be voided and required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:


	•	the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;

	•	the present saleable value of its assets was less than the amount that would be required to pay its probable liability, including contingent liabilities, on its existing debts as they become absolute and mature; or

	•	it could not pay its debts as they became due.

Tax Risks to Common Unitholders

You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for tax purposes or we were to become subject to a material amount ofentity-level taxation, it would substantially reduce the amount of cash available for distribution to you.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss or deduction would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we will be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to our unitholders.

Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount will be adjusted to reflect the impact of that law on us.

If the IRS contests the federal income tax positions we take, the market for our common units may be impacted, and the costs of any IRS contest will reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the

positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may disagree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

You will be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), andnon-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions tonon-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, andnon-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or anon-U.S. person, you should consult your tax advisor before investing in our units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we have adopted.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the technical termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. While we would continue our existence as a Delaware limited liability company, our technical termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a description of the consequences of our termination for tax purposes.

Unitholders may be subject to state and local taxes and return filing requirements.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the

various jurisdictions in which we do business or own property, now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently do business and own assets in Texas and Oklahoma. Although Texas does not currently impose a personal income tax, Oklahoma does and as we make acquisitions or expand our business, we may do business or own assets in other jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference in this prospectus include forward-looking statements. Statements included in this prospectus that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements.


	•	our ability to successfully integrate any acquired assets or operations;

	•	the volatility of prices and market demand for natural gas and natural gas liquids;

	•	our ability to continue to obtain new sources of natural gas supply;

	•	the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;

	•	our ability to retain our key customers;

	•	general economic conditions;

	•	the effects of government regulations and policies; and

	•	other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this prospectus, including without limitation in conjunction with forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this prospectus under “Risk Factors.” All forward-looking statements included in this prospectus and all subsequent written or oral forward-looking statements attributable to us 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.

USE OF PROCEEDS

Unless we specify otherwise in any prospectus supplement, we will use the net proceeds we receive from the sale of securities covered by this prospectus for general corporate purposes, which may include, among other things:


	•	paying or refinancing all or a portion of our indebtedness outstanding at the time; and

	•	funding working capital, capital expenditures or acquisitions.

The actual application of proceeds from the sale of any particular offering of securities using this prospectus will be described in the applicable prospectus supplement relating to such offering. The precise amount and timing of the application of these proceeds will depend upon our funding requirements and the availability and cost of other funds.

RATIOS OF EARNINGS TO FIXED CHARGES

Six Months

Ended

June 30,

Year Ended December 31,

2006

2005

2004

2003

2002

2001

Ratios of Earnings to Fixed Charges

2.6

2.4

—

2.7x

For purposes of computing the ratios of earnings to fixed charges, earnings consist of pre-tax income from continuing operations before equity in (earnings) loss from unconsolidated affiliates plus fixed charges, amortization of capitalized interest and distributions from equity investees less capitalized interest and preference equity distributions. Fixed charges consist of interest expensed and capitalized, distributions on preference units and the estimated interest component of rent expense. Earnings were inadequate to cover fixed charges for the years ended December 31, 2004, 2003 and 2002 by $1.3 million, $5.4 million and $3.1 million, respectively.

DESCRIPTION OF OUR COMMON UNITS

Our common units and subordinated units represent limited liability company interests in us. The holders of these units are entitled to participate in distributions and exercise the rights or privileges available to members under our limited liability company agreement. As of September 30, 2006, we had outstanding 14,861,156 common units, representing a 80.9% member interest and 3,519,126 subordinated units, representing a 19.1% member interest.

Our Limited Liability Company Agreement

Our limited liability company agreement contains additional provisions, many of which apply to holders of our common units. A copy of our limited liability company agreement is included in our other SEC filings and incorporated by reference in this prospectus.

Our Cash Distribution Policy

Please read “Cash Distribution Policy” for a detailed description of the right to receive cash distributions with respect to our common units and subordinated units.

Timing of Distributions

We pay distributions approximately 45 days after March 31, June 30, September 30 and December 31 to unitholders of record on the applicable record date.

Conversion of the Subordinated Units

Each subordinated unit will convert into one common unit at the end of the subordination period, which will end once we meet the financial tests set forth in the 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 tests is met:


	•	distributions of available cash from operating surplus 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;

	•	the “adjusted operating surplus” generated during the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Any quarterly distributions payable to our pre-IPO investors that are used to satisfy any reimbursement obligations associated with our cap on general and administrative expenses are considered distributed to such pre-IPO investors for purposes of determining whether these tests have been met.

Issuance of Additional Units

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and rights to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders. During the subordination period, however, except as we discuss in the following paragraph, we may not issue equity securities ranking senior to the common units or an aggregate of more than 3,519,126 additional common units, or 50% of the common units outstanding immediately after our initial public offering in November 2004, or units on a parity with the common units, in each case, without the approval of the holders of a unit majority.

During the subordination period or thereafter, we may issue an unlimited number of common units without the approval of the unitholders as follows:


	•	upon conversion of the subordinated units;

	•	for the redemption of common units or other equity securities of equal rank with the common units from the net proceeds of an issuance of common units or parity units, but only if the redemption price equals the net proceeds per unit, before expenses, to us;

	•	under employee benefit plans;

	•	upon conversion of units of equal rank with the common units into common units under some circumstances;

	•	in the event of a combination or subdivision of common units;

	•	in connection with an acquisition or an expansion capital improvement that our management determines would increase cash flow from operations per unit on an estimated pro forma basis; or

	•	if the proceeds of the issuance are used to repay certain indebtedness, the cost of which to service is greater than the distribution obligations associated with the units issued in connection with retirement of the debt.

During the subordination period, we may also issue, without unitholder approval, an unlimited number of securities that are similar to subordinated units because such units are not entitled, during the subordination period, to receive distributions of available cash from operating surplus until after the common units and parity units have been paid the minimum quarterly distribution and any arrearages.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other equity securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting rights to which the common units are not entitled.

The holders of common units do not have preemptive rights to acquire additional common units or other securities.

Voting Rights

Common unitholders have the right to vote with respect to the election of our Board of Directors, certain issuances of common units during the subordination period, the issuance of units senior to the common units during the subordination period, certain amendments to our limited liability company agreement, the merger of our company or the sale of all or substantially all of our assets, and the dissolution of our company.

Limited Call Right

If at any time any person owns more than 90% of the then-issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by our management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of the exercise of this right is the greater of:


	•	the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

	•	the current market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read “Risk Factors — Risks Related to Our Structure.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Exchange Listing

Our common units are traded on the Nasdaq Stock Market LLC under the symbol “CPNO.”

Transfer Agent and Registrar Duties

American Stock Transfer and Trust Company serves as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units except the following fees that will be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a holder of a common unit; and

	•	other similar fees or charges.

There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor

transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our limited liability company agreement, each transferee of common units shall be admitted as a unitholder with respect to the common units transferred when such transfer and admission is reflected in our books and records. Additionally, each transferee of common units:


	•	becomes the record holder of the common units;

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our limited liability company agreement;

	•	represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

	•	grants powers of attorney to our officers and any liquidator of our company as specified in the limited liability company agreement; and

	•	makes the consents and waivers contained in the limited liability company agreement.

An assignee will become a unitholder of our company for the transferred common units upon the recording of the name of the assignee on our books and records.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

DESCRIPTION OF OUR DEBT SECURITIES

We will issue our debt securities under an indenture among us, as issuer, the Trustee and any subsidiary guarantors. The debt securities will be governed by the provisions of the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939. We, the Trustee and any subsidiary guarantors may enter into supplements to the Indenture from time to time. If we decide to issue subordinated debt securities, we will issue them under a separate Indenture containing subordination provisions.

This description is a summary of the material provisions of the debt securities and the Indentures. We urge you to read the forms of senior indenture and subordinated indenture filed as exhibits to the registration statement of which this prospectus is a part because those Indentures, and not this description, govern your rights as a holder of debt securities. References in this prospectus to an “Indenture” refer to the particular Indenture under which we issue a series of debt securities. References in this prospectus to “Trustee” refer to U.S. Bank National Association, as further described in “— The Trustee”.

Copano Energy, L.L.C. may issue debt securities in one or more series, and Copano Energy Finance Corporation may be a co-issuer of one or more series of debt securities. Copano Energy Finance Corporation was incorporated under the laws of the State of Delaware in 2005, is wholly-owned by Copano Energy, L.L.C., and has no material assets or any liabilities other than as a co-issuer of debt securities. Its activities will be limited to co-issuing debt securities and engaging in other activities incidental thereto. When used in this section “Description of the Debt Securities,” the terms “we,” “us,” “our” and “issuers” refer jointly to Copano Energy, L.L.C. and Copano Energy Finance Corporation, and the terms “Copano L.L.C.” and “Copano Finance” refer strictly to Copano Energy, L.L.C. and Copano Energy Finance Corporation, respectively.

Specific Terms of Each Series of Debt Securities in the Prospectus Supplement

A prospectus supplement and a supplemental indenture or authorizing resolutions relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:


	•	whether Copano Finance will be a co-issuer of the debt securities;

	•	the guarantors of the debt securities, if any;

	•	whether the debt securities are senior or subordinated debt securities;

	•	the title of the debt securities;

	•	the total principal amount of the debt securities;

	•	the assets, if any, that are pledged as security for the payment of the debt securities;

	•	whether we will issue the debt securities in individual certificates to each holder in registered form, or in the form of temporary or permanent global securities held by a depository on behalf of holders;

	•	the prices at which we will issue the debt securities;

	•	the portion of the principal amount that will be payable if the maturity of the debt securities is accelerated;

	•	the currency or currency unit in which the debt securities will be payable, if not U.S. dollars;

	•	the dates on which the principal of the debt securities will be payable;

	•	the interest rate that the debt securities will bear and the interest payment dates for the debt securities;

	•	any conversion or exchange provisions;

	•	any optional redemption provisions;

	•	any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

	•	any changes to or additional events of default or covenants; and

	•	any other terms of the debt securities.

We may offer and sell debt securities, including original issue discount debt securities, at a substantial discount below their principal amount. The prospectus supplement will describe special U.S. federal income tax and any other considerations applicable to those securities. In addition, the prospectus supplement may describe certain special U.S. federal income tax or other considerations applicable to any debt securities that are denominated in a currency other than U.S. dollars.

Guarantees

If specified in the prospectus supplement respecting a series of debt securities, the subsidiaries of Copano Energy, L.L.C. specified in the prospectus supplement will unconditionally guarantee to each holder and the Trustee, on a joint and several basis, the full and prompt payment of principal of, premium, if any, and interest on the debt securities of that series when and as the same become due and payable, whether at maturity, upon redemption or repurchase, by declaration of acceleration or otherwise. If a series of debt securities is guaranteed, such series will be guaranteed by all subsidiaries other than “minor” subsidiaries as such term is interpreted in securities regulation governing financial reporting for guarantors. The prospectus supplement will describe any limitation on the maximum amount of any particular guarantee and the conditions under which guarantees may be released.

The guarantees will be general obligations of the guarantors. Guarantees of subordinated debt securities will be subordinated to the Senior Indebtedness of the guarantors on the same basis as the subordinated debt

securities are subordinated to the Senior Indebtedness of Copano Energy, L.L.C. “Senior Indebtedness,” with respect to both Copano Energy, L.L.C. and the guarantors, will be defined in a supplemental indenture or authorizing resolutions respecting any issuance of a series of subordinated debt securities, and the definition will be set forth in the prospectus supplement.

Consolidation, Merger or Asset Sale

Each Indenture will, in general, allow us to consolidate or merge with or into another domestic entity. It will also allow each issuer to sell, lease, transfer or otherwise dispose of all or substantially all of its assets to another domestic entity. If this happens, the remaining or acquiring entity must assume all of the issuer’s responsibilities and liabilities under the Indenture including the payment of all amounts due on the debt securities and performance of the issuer’s covenants in the Indenture.

However, each Indenture will impose certain requirements with respect to any consolidation or merger with or into an entity, or any sale, lease, transfer or other disposition of all or substantially all of an issuer’s assets, including:


	•	the remaining or acquiring entity must be organized under the laws of the United States, any state or the District of Columbia; provided that, if Copano Finance is a co-issuer, then it may not merge, or consolidate with or into another entity other than a corporation satisfying such requirement for so long as Copano Energy, L.L.C. is not a corporation;

	•	the remaining or acquiring entity must assume the issuer’s obligations under the Indenture; and

	•	immediately after giving effect to the transaction, no Event of Default (as defined under “— Events of Default and Remedies” below) may exist.

The remaining or acquiring entity will be substituted for the issuer in the Indenture with the same effect as if it had been an original party to the Indenture, and the issuer will be relieved from any further obligations under the Indenture.

No Protection in the Event of a Change of Control

Unless otherwise set forth in the prospectus supplement, the debt securities will not contain any provisions that protect the holders of the debt securities in the event of a change of control of us or in the event of a highly leveraged transaction, whether or not such transaction results in a change of control of us.

Modification of Indentures

We may supplement or amend an Indenture if the holders of a majority in aggregate principal amount of the outstanding debt securities of all series issued under the Indenture affected by the supplement or amendment consent to it. Further, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series may waive past defaults under the Indenture and compliance by us with our covenants with respect to the debt securities of that series only. Those holders may not, however, waive any default in any payment on any debt security of that series or compliance with a provision that cannot be supplemented or amended without the consent of each holder affected. Without the consent of each outstanding debt security affected, no modification of the Indenture or waiver may:


	•	reduce the principal amount of debt securities whose holders must consent to an amendment, supplement or waiver;

	•	reduce the principal of or change the fixed maturity of any debt security;

	•	reduce or waive the premium payable upon redemption or alter or waive the provisions with respect to the redemption of the debt securities (except as may be permitted in the case of a particular series of debt securities);

	•	reduce the rate of or change the time for payment of interest on any debt security;


	•	waive an Event of Default in the payment of principal of or premium, if any, or interest on the debt securities (except a rescission of acceleration of the debt securities by the holders of at least a majority in aggregate principal amount of the debt securities and a waiver of the payment default that resulted from such acceleration);

	•	except as otherwise permitted under the Indenture, release any security that may have been granted with respect to the debt securities;

	•	make any debt security payable in currency other than that stated in the debt securities;

	•	in the case of any subordinated debt security, make any change in the subordination provisions that adversely affects the rights of any holder under those provisions;

	•	make any change in the provisions of the Indenture relating to waivers of past defaults or the rights of holders of debt securities to receive payments of principal of or premium, if any, or interest on the debt securities;

	•	waive a redemption payment with respect to any debt security (except as may be permitted in the case of a particular series of debt securities);

	•	except as otherwise permitted in the Indenture, release any guarantor from its obligations under its guarantee or the Indenture or change any guarantee in any manner that would adversely affect the rights of holders; or

	•	make any change in the preceding amendment, supplement and waiver provisions (except to increase any percentage set forth therein).

We may supplement or amend an Indenture without the consent of any holders of the debt securities in certain circumstances, including:


	•	to establish the form of terms of any series of debt securities;

	•	to cure any ambiguity, defect or inconsistency;

	•	to provide for uncertificated notes in addition to or in place of certified notes;

	•	to provide for the assumption of an issuer’s or guarantor’s obligations to holders of debt securities in the case of a merger or consolidation or disposition of all or substantially all of such issuer’s or guarantor’s assets;

	•	in the case of any subordinated debt security, to make any change in the subordination provisions that limits or terminates the benefits applicable to any holder of Senior Indebtedness of Copano Energy, L.L.C.;

	•	to add or release guarantors pursuant to the terms of the Indenture;

	•	to make any changes that would provide any additional rights or benefits to the holders of debt securities or that do not, taken as a whole, adversely affect the rights under the Indenture of any holder of debt securities;

	•	to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

	•	to evidence or provide for the acceptance of appointment under the Indenture of a successor Trustee;

	•	to add any additional Events of Default; or

	•	to secure the debt securitiesand/or the guarantees.

Events of Default and Remedies

Unless otherwise indicated in the prospectus supplement, “Event of Default,” when used in an Indenture, will mean any of the following with respect to the debt securities of any series:


	•	failure to pay when due the principal of or any premium on any debt security of that series;

	•	failure to pay, within 60 days of the due date, interest on any debt security of that series;

	•	failure to pay when due any sinking fund payment with respect to any debt securities of that series;

	•	failure on the part of the issuers to comply with the covenant described under “— Consolidation, Merger or Asset Sale”;

	•	failure to perform any other covenant in the Indenture that continues for 30 days after written notice is given to the issuers;

	•	certain events of bankruptcy, insolvency or reorganization of an issuer; or

	•	any other Event of Default provided under the terms of the debt securities of that series.

An Event of Default for a particular series of debt securities will not necessarily constitute an Event of Default for any other series of debt securities issued under an Indenture. The Trustee may withhold notice to the holders of debt securities of any default (except in the payment of principal, premium, if any, or interest) if it considers such withholding of notice to be in the best interests of the holders.

If an Event of Default for any series of debt securities occurs and continues, the Trustee or the holders of at least 25% in aggregate principal amount of the debt securities of the series may declare the entire principal of, and accrued interest on, all the debt securities of that series to be due and payable immediately. If this happens, subject to certain conditions, the holders of a majority in the aggregate principal amount of the debt securities of that series can rescind the declaration.

Other than its duties in case of a default, a Trustee is not obligated to exercise any of its rights or powers under either Indenture at the request, order or direction of any holders, unless the holders offer the Trustee reasonable security or indemnity. If they provide this reasonable security or indemnification, the holders of a majority in aggregate principal amount of any series of debt securities may direct the time, method and place of conducting any proceeding or any remedy available to the Trustee, or exercising any power conferred upon the Trustee, for that series of debt securities.

No Limit on Amount of Debt Securities

The Indenture will not limit the amount of debt securities that we may issue, unless we indicate otherwise in a prospectus supplement. The Indenture will allow us to issue debt securities of any series up to the aggregate principal amount that we authorize.

Registration of Notes

We will issue debt securities of a series only in registered form, without coupons, unless otherwise indicated in the prospectus supplement.

Minimum Denominations

Unless the prospectus supplement states otherwise, the debt securities will be issued only in principal amounts of $1,000 each or integral multiples of $1,000.

No Personal Liability

None of the past, present or future partners, incorporators, managers, members, directors, officers, employees, unitholders or stockholders of either issuer or any guarantor will have any liability for the obligations of the issuers or any guarantors under the Indenture or the debt securities or for any claim based

on such obligations or their creation. Each holder of debt securities by accepting a debt security waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the debt securities. The waiver may not be effective under federal securities laws, however, and it is the view of the SEC that such a waiver is against public policy.

Payment and Transfer

The Trustee will initially act as paying agent and registrar under each Indenture. The issuers may change the paying agent or registrar without prior notice to the holders of debt securities, and the issuers or any of their subsidiaries may act as paying agent or registrar.

If a holder of debt securities has given wire transfer instructions to the issuers, the issuers will make all payments on the debt securities in accordance with those instructions. All other payments on the debt securities will be made at the corporate trust office of the Trustee, unless the issuers elect to make interest payments by check mailed to the holders at their addresses set forth in the debt security register.

The Trustee and any paying agent will repay to us upon request any funds held by them for payments on the debt securities that remain unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment as general creditors.

Exchange, Registration and Transfer

Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the Indenture. Holders may present debt securities for exchange or registration of transfer at the office of the registrar. The registrar will effect the transfer or exchange when it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any registration of transfer or exchange of the debt securities. We may, however, require the payment of any tax or other governmental charge payable for that registration.

We will not be required:


	•	to issue, register the transfer of, or exchange debt securities of a series either during a period beginning 15 business days prior to the selection of debt securities of that series for redemption and ending on the close of business on the day of mailing of the relevant notice of redemption or repurchase, or between a record date and the next succeeding interest payment date; or

	•	to register the transfer of or exchange any debt security called for redemption or repurchase, except the unredeemed portion of any debt security we are redeeming or repurchasing in part.

Provisions Relating only to the Senior Debt Securities

The senior debt securities will rank equally in right of payment with all of our other senior and unsubordinated debt. The senior debt securities will be effectively subordinated, however, to all of our secured debt to the extent of the value of the collateral for that debt. We will disclose the amount of our secured debt in the prospectus supplement.

Provisions Relating only to the Subordinated Debt Securities

Subordinated Debt Securities Subordinated to Senior Indebtedness

The subordinated debt securities will rank junior in right of payment to all of the Senior Indebtedness of Copano Energy, L.L.C.

Payment Blockages

The subordinated indenture will provide that no payment of principal, interest and any premium on the subordinated debt securities may be made in the event:


	•	we or our property is involved in any voluntary or involuntary liquidation or bankruptcy;

	•	we fail to pay the principal, interest, any premium or any other amounts on any Senior Indebtedness of Copano Energy, L.L.C. within any applicable grace period or the maturity of such Senior Indebtedness is accelerated following any other default, subject to certain limited exceptions set forth in the subordinated indenture; or

	•	any other default on any Senior Indebtedness of Copano Energy, L.L.C. occurs that permits immediate acceleration of its maturity, in which case a payment blockage on the subordinated debt securities will be imposed for a maximum of 179 days at any one time.

No Limitation on Amount of Senior Debt

The subordinated indenture will not limit the amount of Senior Indebtedness that Copano Energy, L.L.C. may incur, unless otherwise indicated in the prospectus supplement.

Book Entry, Delivery and Form

The debt securities of a particular series may be issued in whole or in part in the form of one or more global certificates that will be deposited with the Trustee as custodian for The Depository Trust Company, New York, New York (“DTC”). This means that we will not issue certificates to each holder. Instead, one or more global debt securities will be issued to DTC, which will keep a computerized record of its participants (for example, your broker) whose clients have purchased the debt securities. The participant will then keep a record of its clients who purchased the debt securities. Unless it is exchanged in whole or in part for a certificated debt security, a global debt security may not be transferred, except that DTC, its nominees and their successors may transfer a global debt security as a whole to one another.

Beneficial interests in global debt securities will be shown on, and transfers of global debt securities will be made only through, records maintained by DTC and its participants.

DTC has provided us the following information: DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the United States Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered under the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants (“Direct Participants”) deposit with DTC. DTC also records the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for Direct Participants’ accounts. This eliminates the need to exchange certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations.

DTC’s book entry system is also used by other organizations such as securities brokers and dealers, banks and trust companies that work through a Direct Participant. The rules that apply to DTC and its participants are on file with the SEC.

DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc.

We will wire all payments on the global debt securities to DTC’s nominee. We and the Trustee will treat DTC’s nominee as the owner of the global debt securities for all purposes. Accordingly, we, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global debt securities to owners of beneficial interests in the global debt securities.

It is DTC’s current practice, upon receipt of any payment on the global debt securities, to credit Direct Participants’ accounts on the payment date according to their respective holdings of beneficial interests in the

global debt securities as shown on DTC’s records. In addition, it is DTC’s current practice to assign any consenting or voting rights to Direct Participants whose accounts are credited with debt securities on a record date, by using an omnibus proxy. Payments by participants to owners of beneficial interests in the global debt securities, and voting by participants, will be governed by the customary practices between the participants and owners of beneficial interests, as is the case with debt securities held for the account of customers registered in “street name.” However, payments will be the responsibility of the participants and not of DTC, the Trustee or us.

Debt securities represented by a global debt security will be exchangeable for certificated debt securities with the same terms in authorized denominations only if:


	•	DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and in either event a successor depositary is not appointed by us within 90 days; or

	•	we determine not to require all of the debt securities of a series to be represented by a global debt security.

Satisfaction and Discharge; Defeasance

Each Indenture will be discharged and will cease to be of further effect as to all outstanding debt securities of any series issued thereunder, when:

(a) either:

(1) all outstanding debt securities of that series that have been authenticated (except lost, stolen or destroyed debt securities that have been replaced or paid and debt securities for whose payment money has theretofore been deposited in trust and thereafter repaid to us) have been delivered to the Trustee for cancellation; or

(2) all outstanding debt securities of that series that have not been delivered to the Trustee for cancellation have become due and payable by reason of the giving of a notice of redemption or otherwise or will become due and payable at their stated maturity within one year or are to be called for redemption within one year under arrangements satisfactory to the Trustee and in any case we have irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust cash in U.S. dollars, non-callable U.S. Government Obligations or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness of such debt securities not delivered to the Trustee for cancellation, for principal, premium, if any, and accrued interest to the date of such deposit (in the case of debt securities that have been due and payable) or the stated maturity or redemption date;

(b) we have paid or caused to be paid all other sums payable by us under the Indenture; and

(c) we have delivered an officers’ certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

The debt securities of a particular series will be subject to legal or covenant defeasance to the extent, and upon the terms and conditions, set forth in the prospectus supplement.

Governing Law

Each Indenture and all of the debt securities will be governed by the laws of the State of New York.

The Trustee

We will enter into the Indentures with a trustee that is qualified to act under the Trust Indenture Act of 1939, as amended, and with any other trustees chosen by us and appointed in a supplemental indenture for a particular series of debt securities. Unless we otherwise specify in the applicable prospectus supplement, the initial trustee for each series of debt securities will be U.S. Bank National Association. We may maintain a

banking relationship in the ordinary course of business with U.S. Bank National Association and one or more of its affiliates.

Resignation or Removal of Trustee

If the trustee has or acquires a conflicting interest within the meaning of the Trust Indenture Act, the trustee shall either eliminate its conflicting interest or resign, to the extent and in the manner provided by, and subject to the provisions of, the Trust Indenture Act and the applicable Indenture. Any resignation will require the appointment of a successor trustee under the applicable Indenture in accordance with the terms and conditions of such Indenture.

The trustee may resign or be removed by us with respect to one or more series of debt securities and a successor trustee may be appointed to act with respect to any such series. The holders of a majority in aggregate principal amount of the debt securities of any series may remove the trustee with respect to the debt securities of such series.

Limitations on Trustee if it is Our Creditor

Each Indenture will contain certain limitations on the right of the trustee, in the event that it becomes a creditor of an issuer or a guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise.

Annual Trustee Report to Holders of Debt Securities

The trustee is required to submit an annual report to the holders of the debt securities regarding, among other things, the trustee’s eligibility to serve as such, the priority of the trustee’s claims regarding certain advances made by it, and any action taken by the trustee materially affecting the debt securities.

Certificates and Opinions to be Furnished to Trustee

Each Indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of an Indenture, every application by us for action by the trustee shall be accompanied by a certificate of certain of our officers and an opinion of counsel (who may be our counsel) stating that, in the opinion of the signers, all conditions precedent to such action have been complied with by us.

CASH DISTRIBUTION POLICY

Quarterly Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, we will distribute all of our available cash to unitholders of record on the applicable record date.

Available Cash. Available cash for any quarter consists of cash on hand at the end of that quarter, plus cash on hand from working capital borrowings made after the end of the quarter but before the date of determination of available cash for the quarter, less cash reserves. If we are not in compliance with covenants contained in our credit facilities or the indenture governing our 81/8% senior notes due 2016, we will be unable to make distributions of available cash. In addition, if we issue debt securities in the future, then the indenture governing the debt securities will likely contain covenants that limit our ability to make distributions to our unitholders if we fail to comply with such covenants. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Description of Our Indebtedness” in our Annual Report onForm 10-K for the year ended December 31, 2005 incorporated herein by reference and Note 5 to our quarterly report onForm 10-Q for the quarter ended June 30, 2006 incorporated herein by reference for a more detailed description of our senior secured revolving credit facility and our 81/8% senior notes due 2016. Please read our current report onForm 8-K filed on October 5, 2006 for a more detailed description of our $100 million senior unsecured term loan.

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.40 per unit, or $1.60 per unit per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses. There is no guarantee, however, that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or if an event of default is existing, under our credit facilities or under the indenture governing our 81/8% senior notes due 2016 or any indenture governing future issuances of debt securities.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We distribute available cash from operating surplus differently than available cash from capital surplus. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Operating Surplus. For any period, operating surplus generally means:


	•	our cash balance on the closing date of our initial public offering; plus

	•	$12.0 million (as described below); plus

	•	all of our cash receipts from operations since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; plus

	•	general and administrative expense reimbursement by our existing investors of the amount in excess of our cap on general and administrative expenses for the three-year period following our initial public offering; less

	•	all of our operating expenditures since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

	•	the amount of cash reserves for future operating expenditures.

As reflected above, operating surplus includes $12.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect the actual cash on hand at the closing of our initial public offering that was available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $12.0 million of cash we receive in the future from non-operating sources, such as asset sales outside the ordinary course of business, sales of our equity and debt securities, and long-term borrowings, that would otherwise be distributed as capital surplus.

We are currently unable to borrow under our credit facilities to pay distributions of operating surplus to unitholders because no such borrowings would constitute “working capital borrowings” pursuant to the definition contained in our limited liability company agreement. Because we will be unable to borrow money to pay our minimum quarterly distribution until such time as we establish a facility that meets the definition contained in our limited liability company agreement, our ability to pay the minimum quarterly distribution in any quarter is solely dependent on our ability to generate sufficient operating surplus with respect to that quarter. Because we are unable to cover a shortfall in the minimum quarterly distribution with working capital borrowings, there is an additional risk that we will not be able to pay the full minimum quarterly distribution

in any particular quarter until such time as we establish a facility that meets the definition contained in our limited liability company agreement.

As described above, operating surplus is reduced by the amount of our maintenance capital expenditures but not our expansion capital expenditures. Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. For example, expansion of compression facilities to increase throughput capacity or the acquisition of additional pipelines are considered expansion capital expenditures. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. We treat costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets as operations and maintenance expenses as we incur them. Our management has the discretion to determine how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures reduce operating surplus, from which we pay the minimum quarterly distribution, but expansion capital expenditures do not.

Capital Surplus. Capital surplus consists of:


	•	borrowings other than working capital borrowings;

	•	sales of debt and equity securities; and

	•	sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Subordination Period

General. During the subordination period, which we define below, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.40 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Upon expiration of the subordination period, all subordinated units will convert into common units on aone-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash, and the common units will no longer be entitled to arrearages.

Expiration of Subordination Period. The subordination period will extend until the first day of any quarter beginning after December 31, 2006 that each of the following tests is met:


	•	distributions of available cash from operating surplus 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;

	•	the “adjusted operating surplus” (as defined below) generated during the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Any quarterly distributions payable to our existing investors that are used to satisfy any reimbursement obligations associated with our cap on general and administrative expenses shall be considered distributed to such existing investors for purposes of determining whether the test above has been met.

Adjusted Operating Surplus. Adjusted operating surplus is a measure that we use to determine the operating surplus that is actually earned in a test period by excluding items from prior periods that affect operating surplus in the test period. Adjusted operating surplus consists of:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus will not be reduced by the amount of general and administrative expense reimbursement from our existing investors.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	First, to the common unitholders until we have distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	Second, to the common unitholders until we have distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	Third, to the subordinated unitholders until we have distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	Thereafter, to all unitholders pro rata.

Distributions of Available Cash from Operating Surplus After the Subordination Period

When the subordination period ends, all remaining subordinated units will convert into common units on aone-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will be Made. We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	First, to all unitholders, pro rata, until we have distributed for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

	•	Second, to the common unitholders, pro rata, until we have distributed for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. Our limited liability company agreement treats a distribution of capital surplus as the repayment of capital from our initial public offering, which is a return of capital. Our initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered capital.” Each time a distribution of capital surplus is made, the minimum quarterly distribution

will be reduced in the same proportion as the corresponding reduction in the unrecovered capital. Any distribution of capital surplus before the unrecovered capital is reduced to zero cannot be applied, however, to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in any offering in an amount equal to the initial unit price and have paid all arrearages, we will reduce the minimum quarterly distribution to zero, and then make all future distributions from operating surplus.

Adjustment of Minimum Quarterly Distribution

In addition to adjusting the minimum quarterly distribution to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the unrecovered capital;

	•	the number of common units issuable during the subordination period without a unitholder vote; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if atwo-for-one split of the common and subordinated units should occur, the minimum quarterly distribution and the unrecovered capital would each be reduced to 50% of its initial level and the number of common units issuable during the subordination period without a unitholder vote would double. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution level for each quarter by multiplying the minimum quarterly distribution by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our board of directors’ estimate of our aggregate liability for the income taxes payable by reason of that legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders in accordance with their respective capital account balances, as adjusted to reflect any taxable gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of taxable gain upon liquidation are intended, to the extent possible, to allow the holders of common units to receive proceeds equal to their unrecovered capital plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any arrearages in the payment of the minimum quarterly distribution on the common units from previous quarters prior to any allocation of gain to subordinated units. There may not be sufficient taxable gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units.

If there are losses upon liquidation, they first will be allocated to the subordinated units until the capital accounts of the subordinated units have been reduced to zero and then to the common units until the capital accounts of the common units have been reduced to zero. Any remaining loss will be allocated pro rata to all unitholders.

MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to us, insofar as it relates to United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Copano Energy, L.L.C. and its operating subsidiaries.

This section does not address all federal income tax matters that affect us or our unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (“REITs”) or mutual funds. Accordingly, each prospective unitholder is encouraged to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our common units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly or indirectly by the unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Vinson & Elkins L.L.P.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:

(1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

(2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

(3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A limited liability company is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each unitholder of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a unitholder are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interests.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to herein as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the processing, transportation and marketing of natural resources, including natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our current gross income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that more than 90% of our current gross income constitutes qualifying income.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on the following factual representations made by us and the assumption that we will continually comply with such representations:

(a) We have not elected nor will we elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Unitholder Status

Unitholders who become members of our company will be treated as partners of our company for federal income tax purposes. Also:

(a) assignees who have executed and delivered transfer applications, and are awaiting admission as members, and

(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

will be treated as partners of our company for federal income tax purposes.

As there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, loss, or deduction would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to the consequences of their status as partners in our company for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gain, loss and deduction for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of those common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash,

which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recaptureand/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Initial Basis of Common Units

A unitholder’s initial tax basis for his common units generally will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis generally will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or certain tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment, or any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Similarly, a unitholder’s share of our net income may not be offset by any other current or carryover losses from other passive activities, including those attributable

to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributable to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units and not to the subordinated units, gross income will be allocated to the recipients to the extent of those distributions. If we have a net loss for the entire year, that amount of loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder who purchases common units in an offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not

expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

Our pre-IPO investors have agreed to reimburse us for our general and administrative expenses in excess of stated levels (subject to certain limitations) through December 31, 2007. We treat the reimbursements of general and administrative expenses made by the pre-IPO investors as a capital contribution to us. At the end of each quarter, we make a corresponding special allocation of deductions to our pre-IPO investors in the amount of the reimbursements for the general and administrative expenses received by us.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our limited liability company agreement will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the

exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than twelve months at the time of disposition.

Section 754 Election

We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, “— Allocation of Income, Gain, Loss and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we have adopted as to property other than certain goodwill properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. If we elect a method other than the remedial method with respect to a goodwill property, TreasuryRegulation Section 1.197-2(g)(3) generally requires that the Section 743(b) adjustment attributable to an amortizable Section 197 intangible, which includes goodwill property, should be treated as a newly-acquired asset placed in service in the month when the purchaser acquires the common unit. Under TreasuryRegulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our limited liability company agreement, our board of directors is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Tax Treatment of Operations — Uniformity of Units.” If we elect a method other than the remedial method with respect to a goodwill property, the common basis of such property is not amortizable. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion asnon-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with TreasuryRegulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets and TreasuryRegulation Section 1.197-2(g)(3). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct

interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Tax Treatment of Operations — Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built — in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Because we may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there

is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury RegulationSection 1.167(c)-1(a)(6) and TreasuryRegulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with TreasuryRegulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets and Treasury RegulationSection 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of

depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. A significant portion of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on aForm W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including aSchedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor

counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. We have appointed Copano Partners Trust as our Tax Matters Partner, subject to redetermination by our board of directors from time to time.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

(1) a person that is not a United States person,

(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3) a tax-exempt entity;

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations,

substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority,” or

(2) as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” a term that in this context does not appear to include us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Texas and Oklahoma. Although Texas does not currently impose a personal income tax, Oklahoma does and as we make acquisitions or expand our business, we may do business or own assets in other jurisdictions that impose a personal income tax. Although an analysis of those various taxes is

not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collection.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth on the prospectus supplement relating to the offering of debt securities.

LEGAL MATTERS

In connection with particular offerings of the securities in the future, and if stated in the applicable prospectus supplement, the validity of those securities may be passed upon for us by Vinson & Elkins L.L.P. and for any underwriters or agents by counsel named in the applicable prospectus supplement.

EXPERTS

The consolidated financial statements and management’s report on the effectiveness of internal control over financial reporting incorporated in this prospectus by reference from the Copano Energy, L.L.C. Annual Report onForm 10-K have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference, and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The financial statements of ScissorTail Energy, LLC as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004 incorporated by reference in this prospectus have been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report with respect thereto, and are incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and other reports and other information electronically with the SEC. You may read and copy any document we file with the SEC at the SEC’s public reference room at Room 1580, 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC at1-800-732-0330 for information on the public reference room. You can also find our filings on the SEC’s website at http://www.sec.gov. We also

make available free of charge on our website, at http:/ /www.copanoenergy.com, all materials that we file electronically with the SEC, including our annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Information contained on our website is not part of this prospectus, unless specifically so designated and filed with the SEC.

We have filed with the SEC a registration statement onForm S-3 relating to the securities covered by this prospectus. This prospectus is a part of the registration statement and does not contain all the information in the registration statement. Whenever a reference is made in this prospectus to a contract or other document of Copano Energy, L.L.C., the reference is only a summary and you should refer to the exhibits that are a part of the registration statement for a copy of the contract or other document. You may review a copy of the registration statement at the SEC’s public reference room in Washington, D.C., as well as through the SEC’s website.

We “incorporate by reference” information into this prospectus, which means that we disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus, except for any information superseded by information contained expressly in this prospectus, and the information we file later with the SEC will automatically supersede this information. You should not assume that the information in this prospectus is current as of any date other than the date on the front page of this prospectus.

Any information that we file under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, and that is deemed “filed,” with the SEC will automatically update and supersede this information. We incorporate by reference the documents listed below:


	•	Our Annual Report onForm 10-K for the year ended December 31, 2005;

	•	Our Quarterly Reports onForm 10-Q for the quarterly periods ended March 31, 2006 and June 30, 2006; and

	•	Our Current Reports onForm 8-K filed on August 3, 2005; January 3, 2006; January 19, 2006; January 20, 2006 (Items 8.01 and 9.01); February 3, 2006; February 8, 2006; February 21, 2006; April 6, 2006; April 7, 2006; April 19, 2006; May 30, 2006; June 1, 2006; July 20, 2006; October 5, 2006 and October 19, 2006.

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s web site at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at www.copanoenergy.com, or by writing or calling us at the following address:

Copano Energy, L.L.C.
Investor Relations
2727 Allen Parkway, Suite 1200
Houston, Texas 77019
(713) 621-9547

Copano Energy, L.L.C. (CPNO) 424B2Prospectus for primary offering