Form 424B5

We are selling 5,000,000 common units representing limited liability company interests in Copano Energy, L.L.C. Our common units trade on the Nasdaq Global Select Market under the symbol “CPNO.” The last reported sales price of our common units on the Nasdaq Global Select Market on January 12, 2012 was $35.36 per common unit.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page S-13 of this prospectus supplement.

We have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering.

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 is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about January 19, 2012.

You should not assume that the information contained in this prospectus supplement, the accompanying prospectus or any free writing prospectus is accurate as of any date other than the date on the front of those documents or that any information that 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 those dates.

We are not making an offer to sell or soliciting offers to buy securities in any jurisdiction where the offer or sale is not permitted.

You should not consider any information contained in or incorporated by reference into this prospectus supplement or the accompanying prospectus to be legal, business or tax advice. You should consult your own attorney, business advisor and tax advisor for legal, business and tax advice regarding an investment in our securities.

This document is in two parts. The first part is the prospectus supplement, which describes our business and the specific terms of this offering of common units and also adds to and updates information contained in the accompanying prospectus and the documents incorporated by reference into this prospectus supplement and the accompanying prospectus. The second part, the accompanying prospectus dated November 2, 2009, gives more general information about securities we may offer from time to time, some of which may not apply to this offering.

We are not making an offer to sell securities in any jurisdiction where the offer or sale is not permitted.

Before investing in the common units, you should read both this prospectus supplement and the accompanying prospectus together with the additional information described under the heading “Where You Can Find More Information.”

In making your investment decision, you should rely only on the information contained in or incorporated by reference in this prospectus supplement and the accompanying prospectus and any free writing prospectus prepared by or on our behalf. To the extent that there is a conflict between the information contained in this prospectus supplement and the information contained in the accompanying prospectus or any earlier-dated document incorporated by reference, you should rely on the information in this prospectus supplement. Neither we nor the underwriters have authorized anyone to provide you with any other information. If anyone provides you with additional, different or inconsistent information, you should not rely on it.

This prospectus supplement, the accompanying prospectus and the documents we incorporate by reference contain certain “forward-looking” statements within the meaning of the federal securities laws. Statements included in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference 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 references to future goals or intentions or other such references, are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include assertions related to plans for growth of our 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 forecasted in these statements. Any differences could be caused by a number of factors, including, but not limited to:

This prospectus supplement, the accompanying prospectus and the documents incorporated by reference include cautionary statements identifying important factors that could cause actual results to materially differ from our expectations, including in conjunction with the forward-looking statements 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 or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

SUMMARY

This summary highlights information contained elsewhere or incorporated by reference in this prospectus supplement and the accompanying prospectus. It does not contain all of the information you should consider before making an investment decision. You should read the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and any other documents to which we refer for a more complete understanding of this offering and our business. Please read the section entitled “Risk factors” beginning on page S-13 of this prospectus supplement and contained in our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 for more information about important risks that you should consider before buying the common units in this offering. Throughout this prospectus supplement and the accompanying 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 otherwise indicated or the context otherwise requires.

Copano Energy, L.L.C.

Overview

We are an energy company engaged in the business of providing midstream services to natural gas producers, including gathering and transportation of natural gas and related services such as compression, dehydration, treating, processing, nitrogen rejection and marketing services. We also provide transportation and fractionation services for natural gas liquids, or NGLs. We were formed in August 2001 as a Delaware limited liability company to acquire entities operating under the Copano name since 1992, and to serve as a holding company for our operating subsidiaries.

Our Operations

Our natural gas pipelines collect natural gas from wellheads or designated points near producing wells. We treat and process natural gas as needed to remove contaminants and to extract mixed NGLs, and we deliver the resulting residue gas to third-party pipelines, local distribution companies, power generation facilities and industrial customers. We sell extracted NGLs as a mixture or as fractionated purity products and deliver them through our plant interconnects or NGL pipelines. We process natural gas from our own gathering systems and from third-party pipelines, and in some cases we deliver natural gas and mixed NGLs to third parties who provide us with transportation, processing or fractionation services.

Our Operating Segments

Through our subsidiaries and equity investments, we own and operate natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. We operate in Texas, Oklahoma, Wyoming and Louisiana. We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Texas, Oklahoma and Rocky Mountains.

•

Texas. Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation services. This segment includes our 62.5% interest in Webb/Duval Gatherers, 50% interest in Eagle Ford Gathering LLC (“Eagle Ford Gathering”), 50% interest in Liberty Pipeline Group, LLC (“Liberty Pipeline Group”) and 50% interest in Double Eagle Pipeline LLC (“Double Eagle Pipeline”) and a processing plant located in Southwest Louisiana.

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Oklahoma. Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our majority interest in Southern Dome, LLC (“Southern Dome”).

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Rocky Mountains. Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas and compressor rental services. This segment includes our 51% interest in Bighorn Gas Gathering, L.L.C. (“Bighorn”) and our 37.04% interest in Fort Union Gas Gathering, L.L.C. (“Fort Union”).

Our operating segments are summarized in the following table:


Segment	Assets	Pipeline Miles /Number of Processing Plants		Pipeline Throughput/Plant Inlet Capacity(1)(2)
Texas	Natural Gas Pipelines(3)		2,260		1,900,400
	Processing Plants		3		1,000,000
	NGL Pipelines(4)		370		117,000

Oklahoma	Natural Gas Pipelines		3,820		350,000
	Processing Plants(5)		7		236,000

Rocky Mountains	Natural Gas Pipelines(6)		600		1,550,000

(1)	Capacity values generally are based on current operating configurations and could be increased or decreased through addition or removal of compression, delivery meter capacity or other facility modifications.

(2)	Natural gas pipeline throughputs and plant inlet capacity are presented in Mcf/d. NGL pipeline throughputs and capacity are presented in Bbls/d.

(3)	Includes the 188-mile gathering system owned by Eagle Ford Gathering, an unconsolidated company in which we own a 50% interest, and the 153-mile gathering system owned by Webb/Duval Gatherers, an unconsolidated partnership in which we own a 62.5% interest.

(4)	Includes the 87-mile NGL pipeline owned by Liberty Pipeline Group, an unconsolidated company in which we own a 50% interest.

(5)	Includes the Southern Dome plant owned by Southern Dome, an unconsolidated company in which we own a majority interest.

(6)	Owned by Bighorn and Fort Union, unconsolidated companies in which we own 51.0% and 37.04% interests, respectively. We do not operate Fort Union.

Our Business Strategy

Our management team is committed to our mission of building a diversified midstream company with scale, stability of cash flows, above-average returns on invested capital and providing secure and growing distributions to our unitholders. Key elements of our strategy include:

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Executing on organic growth opportunities and bolt-on acquisitions. We pursue capital projects and complementary acquisitions that we believe will enhance our ability to increase cash flows from our existing assets by capitalizing on our existing infrastructure, personnel and customer relationships. For example, we have completed significant expansions of our assets to capitalize on significant activity in the Eagle Ford Shale, near our Houston Central complex in Texas, in the North Barnett Shale Combo, near our Saint Jo processing plant in Texas, and in the Woodford Shale, near our Mountains gathering systems in Oklahoma, and we have undertaken further expansion in Texas to meet continued demand from Eagle Ford Shale producers. In addition, where our pipelines and processing or fractionation facilities have excess capacity, we have opportunities to increase throughput volume and cash flow with minimal incremental costs. We seek to increase volumes and utilization of capacity by aggressively marketing our services to producers to connect new supplies of natural gas.

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Reducing sensitivity to commodity prices. The volatility of natural gas and NGL prices is a key consideration as we enter into new contracts and review opportunities for growth. Our goal is to position ourselves to achieve stable cash flows in a variety of market conditions. Generally, we pursue contracts under which the compensation for our services is not directly dependent on commodity prices. For example, we have focused on replacing commodity-sensitive contracts with fee-based contracts in executing our strategy to increase volumes from the Eagle Ford Shale, the north Barnett Shale Combo play and the Woodford Shale. In addition, we pursue opportunities to increase the fee-based component of our contract portfolio through acquisitions or other growth projects. To the extent that our contracts are commodity sensitive, we use derivative instruments to hedge our exposure to commodity price risk. We have established a product-specific, option-focused portfolio designed to allow us to meet our debt service, maintenance capital expenditure and similar requirements, along with our distribution objectives, despite fluctuations in commodity prices.

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Expanding through greenfield opportunities and strategic acquisitions. We pursue significant greenfield projects that leverage our strengths through alignment with producers and downstream customers. We also pursue potential acquisitions in new regions that we believe will enhance the scale and diversity of our assets or otherwise offer cash flow and operational growth opportunities that are attractive to us.

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Pursuing growth judiciously. We believe that a disciplined approach in selecting new projects will better enable us to choose opportunities that deliver value for our company and our unitholders. In analyzing a particular acquisition, expansion or greenfield project, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets or projects, strategic fit in relation to our existing business, expertise and management personnel required, capital required to integrate and maintain the assets involved, and the surrounding competitive environment. From a financial perspective, we analyze the rate of return the assets are expected to generate relative to our cost of capital under various commodity price scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.

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Developing and exploiting flexibility in our operations. Flexibility is a fundamental consideration underlying our approach to developing, expanding or acquiring assets. We can modify the operation of our assets to maximize our cash flows. For example, we can operate several of our processing plants in ethane-rejection mode as commodity price environments or operating conditions warrant. In 2010 and 2011, we focused on developing our ability to offer Eagle Ford Shale producers access to multiple natural gas and NGL markets. Multiple residue markets are available at the tailgate of our Houston Central complex, and in 2010 and 2011 we secured alternatives for NGL handling through initiatives such as the startup and expansion of our Houston Central fractionator, our Liberty pipeline project and our execution of third-party fractionation or purchase arrangements for NGLs or purity products, including agreements with petrochemical customers along the Texas Gulf Coast.

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Maintaining a strong balance sheet and access to liquidity. We are committed to pursuing growth in a way that allows us to maintain the strength of our balance sheet and a liquidity position that allows us to execute our business strategy in various commodity price environments. For example, we financed a substantial portion of our Eagle Ford Shale capital expenditures though a private placement of preferred equity with an affiliate of TPG Capital, L.P., which included a paid-in-kind distribution feature that allowed us the flexibility to maintain a strong balance sheet and liquidity position during construction and expansion of our assets and prior to generating cash flow from these projects.

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Maintaining an approach to business founded on a culture of integrity, service and creativity. We believe that the dedication of our employees is a critical component of our success. We seek to maintain a company culture that fosters integrity and encourages innovation and teamwork, which we believe will allow us to deliver the superior service required to establish and maintain valued long-term commercial relationships.

Recent Developments

Recent Eagle Ford Shale projects. We have undertaken various expansion capital projects in Texas to accommodate volume growth from the Eagle Ford Shale play.

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Condensate gathering joint venture with Magellan Midstream Partners, L.P. Effective December 15, 2011, we entered into agreements to form Double Eagle Pipeline, a 50/50 joint venture with Magellan Midstream Partners, L.P. (“Magellan”), to provide condensate gathering and product terminalling services to Eagle Ford Shale producers. The joint venture intends to construct a 182-mile pipeline system extending from Gardendale, Texas, in LaSalle County to Three Rivers, Texas, in Live Oak County, Texas then extending north into central DeWitt County, Texas. We will convert to condensate service and dedicate to the joint venture an existing natural gas pipeline that extends from near Three Rivers, Texas to Nueces Bay, Texas, near Corpus Christi. Magellan will dedicate to the joint venture storage assets, as well as marine vessel loading facilities at the Port of Corpus Christi. The pipeline from Three Rivers to Corpus Christi may begin service as early as the fourth quarter of 2012, while the remaining joint venture assets are expected to begin service in the second quarter of 2013. Our 50% share of estimated construction costs associated with the joint venture and our costs to convert our existing pipeline are expected to total approximately $110 million. The joint venture project is supported by long-term customer commitments from two major producers with significant acreage in the rich gas window of the Eagle Ford Shale.

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DK pipeline expansion placed in service in December 2011. In December 2011, we placed into service 58 miles of newly constructed pipeline through Lavaca and Colorado Counties, Texas that directly connect our existing 38-mile DK pipeline in DeWitt and Karnes Counties, Texas to our Houston Central complex. The pipeline extension has increased the DK pipeline’s capacity from 225,000 MMBtu per day to 350,000 MMBtu per day. We have secured firm producer volume commitments for aggregate production of approximately 120,000 MMBtu per day through contracts with an average term of six years, as well as an additional commitment for production from approximately 135,000 gross acres in the Eagle Ford Shale.

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Eagle Ford Gathering pipeline placed in full service in December 2011. Eagle Ford Gathering, our joint venture with Kinder Morgan (“Kinder Morgan”), completed construction of a 117-mile pipeline and began limited service in August 2011. Eagle Ford Gathering then placed the pipeline into full service on December 1, 2011. The joint venture has secured fee-based contracts with several producers, which have an average term of 10 years and provide volume commitments of 637,500 MMBtu per day.

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Eagle Ford Gathering crossover pipeline placed in service in October 2011. Eagle Ford Gathering recently completed construction of a 54-mile crossover pipeline between existing Kinder Morgan pipelines, a 5,000 horsepower compressor station and additional lateral pipelines, enabling Eagle Ford Gathering to deliver natural gas from the crossover pipeline to Williams Field Services’ Markham processing plant and Formosa Hydrocarbon Company’s (“Formosa”) Point Comfort facility for processing and associated fractionation services under long-term agreements. Eagle Ford Gathering began deliveries to Williams Field Services via the crossover pipeline in October, and we anticipate that it will begin deliveries to Formosa in early 2012.

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Liberty pipeline placed in service in September 2011. Our Liberty Pipeline Group joint venture with Energy Transfer Partners completed construction of an NGL pipeline that extends approximately 87 miles, from our Houston Central complex in Colorado County, Texas, first to an NGL product storage facility in Matagorda County, Texas, and then to Formosa’s Point Comfort facility. We have 37,500 barrels per day of firm capacity on the Liberty pipeline, which enables us to transport mixed NGLs for delivery to Formosa under a long-term fractionation and product purchase agreement. Our agreement with Formosa initially provides us access to 5,000 to 7,000 barrels per day of fractionation

and NGL product sales, and the agreement will provide us with up to 37,500 barrels per day of fractionation and product sales beginning in early 2013, after Formosa completes an expansion of its facilities.

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Houston Central NGL fractionator expansion completed in October 2011. In October 2011, we completed the expansion of the fractionator at our Houston Central complex from 22,000 to 44,000 barrels per day. We expect to be able to utilize the full expanded fractionation capacity in early 2012, after we complete an upgrade to our purity ethane takeaway facilities. We also expect to complete a related upgrade of the cryogenic facility at our Houston Central complex in early 2012, which will increase the plant’s ability to process NGL-rich natural gas from the Eagle Ford Shale.

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Houston Central processing expansion. In April 2011, we announced plans to expand our Houston Central complex with the addition of a new 400,000 Mcf per day cryogenic processing plant, for total processing capacity of 1.1 Bcf per day. We have obtained the necessary permits and procured long-lead equipment for the project. We have begun site construction and expect to complete the expansion late in the first quarter of 2013.

2012 capital projects. Our estimated 2012 expansion capital expenditures for board-approved projects total $310 million, which includes expenditures for our joint venture with Magellan, our Houston Central processing expansion and additional gathering infrastructure in the Eagle Ford Shale.

Declaration of distribution. On January 11, 2012, our Board of Directors declared a cash distribution for the three months ended December 31, 2011 of $0.575 per common unit. The distribution will be paid on February 9, 2012 to all common unitholders of record at the close of business on January 26, 2012. Based on our common units outstanding at December 31, 2011, and the common units to be sold in this offering (assuming the underwriters’ option to purchase additional common units is not exercised), the distribution would total approximately $41.6 million.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 2727 Allen Parkway, Suite 1200, Houston, Texas 77019. Our telephone number at our principal executive offices is (713) 621-9547. We maintain a website at www.copano.com. The information on our website is not part of this prospectus supplement, and you should rely only on information contained in or incorporated by reference herein and any free writing prospectus filed in connection with this offering when making an investment decision.

The Offering

Common units offered by Copano Energy, L.L.C.

5,000,000 common units; or 5,750,000 common units if the underwriters exercise in full their option to purchase an additional 750,000 common units.

Common units outstanding immediately after this offering(1)

71,341,458 common units; or 72,091,458 common units if the underwriters exercise in full their option to purchase an additional 750,000 common units.

Use of proceeds

We expect to receive net proceeds of approximately $163.0 million from the sale of 5,000,000 common units offered by this prospectus supplement, after deducting underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters exercise their option to purchase 750,000 additional common units in full, we expect to receive additional net proceeds of approximately $24.5 million. We intend to use the net proceeds from this offering (and the net proceeds from any exercise of the underwriters’ option to purchase additional common units) to repay a portion of the outstanding indebtedness under our revolving credit facility. Please read “Use of Proceeds.”

Cash distributions

Under our limited liability company agreement, we must distribute all of our cash on hand at the end of each quarter, less reserves established by our board of directors. We refer to this cash as “available cash,” and we define it in our limited liability company agreement. Please read “Cash Distribution Policy” on page 39 of the accompanying prospectus.

On January 11, 2012, we declared a cash distribution with respect to the fourth quarter of 2011 of $0.575 per common unit, or $2.30 per common unit on an annualized basis, to unitholders of record at the close of business on January 26, 2012. Purchasers of the common units offered by this prospectus supplement will receive this cash distribution on February 9, 2012.

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for the distribution for the fourth calendar quarter of 2014, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. Please read “Material Tax Considerations” in this prospectus supplement for the basis of this estimate.

Conflicts of Interest

As described in “Use of Proceeds,” the net proceeds from this offering (and the net proceeds from any exercise of the underwriters’ option to purchase additional common units) will be used to repay a

(1)

Includes 43,800 restricted common units outstanding under our long-term incentive plan as of December 31, 2011. Excludes other outstanding awards under our long-term incentive plan as of December 31, 2011, including 996,502 phantom units, 765,952 options to acquire common units, of which 638,692 are exercisable and 407,125 unit appreciation rights, of which 36,845 are exercisable.

SUMMARY HISTORICAL FINANCIAL INFORMATION

The following tables show our summary historical financial information as of and for the periods indicated. We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes incorporated herein by reference. The tables should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2011, June 30, 2011 and September 30, 2011, which are incorporated herein by reference.


	Nine Months ended September 30,						Year ended December 31,
	2011			2010			2010			2009			2008
	(in thousands, except per unit information)
Statement of Operations:
Revenue:
Natural gas sales	$	348,538		$	292,559		$	381,453		$	316,686		$	747,258
Natural gas liquids sales		521,129			353,119			490,980			406,662			597,986
Transportation, compression and processing fees		82,706			47,539			68,398			55,983			59,006
Condensate and other		37,299			41,204			54,333			40,715			50,169

Total revenue		989,672			734,421			995,164			820,046			1,454,419

Costs and expenses:
Cost of natural gas and natural gas liquids(1)		779,986			551,939			745,074			576,448		$	1,178,304
Transportation(1)		19,202			16,619			22,701			24,148			21,971
Operations and maintenance		46,953			38,337			53,487			51,477			53,824
Depreciation, amortization and impairment		56,143			46,002			62,572			56,975			52,916
General and administrative		34,530			31,311			40,347			39,511			45,571
Taxes other than income		4,029			3,658			4,726			3,732			3,019
Equity in loss (earnings) from unconsolidated affiliates		158,581			19,788			20,480			(4,600	)		(6,889	)

Total costs and expenses		1,099,424			707,654			949,387			747,691			1,348,716

Operating income		(109,752	)		26,767			45,777			72,355			105,703
Other income (expense):
Interest and other income		31			59			78			1,202			1,174
Gain (loss) on retirement of unsecured debt		(18,233	)		—			—			3,939			15,272
Interest and other financing costs		(34,450	)		(41,239	)		(53,605	)		(55,836	)		(64,978	)

(Loss) income before income taxes and discontinued operations		(162,404	)		(14,413	)		(7,750	)		21,660			57,171
Provision for income taxes		(1,161	)		(660	)		(931	)		(794	)		(1,249	)

(Loss) income from continuing operations		—			—			(8,681	)		20,866			55,922
Discontinued operations, net of tax(2)		—			—			—			2,292			2,291

Net (loss) income		(163,565	)		(15,073	)		(8,681	)		23,158			58,213
Preferred unit distributions		(24,235	)		(7,500	)		(15,188	)		—			—

Net (loss) income to common units	$	(187,800	)	$	(22,573	)	$	(23,869	)	$	23,158		$	58,213

Basic net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$	(2.84	)	$	(0.36	)	$	(0.37	)	$	0.39		$	1.15
Income per common unit from discontinued operations		—			—			—			0.04			0.05

Net (loss) income per common unit	$	(2.84	)	$	(0.36	)	$	(0.37	)	$	0.43		$	1.20

Weighted average number of common units		66,125			63,193			63,854			54,395			48,513
Diluted net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$	(2.84	)	$	(0.36	)	$	(0.37	)	$	0.36		$	0.97
Income per common unit from discontinued operations		—			—			—			0.04			0.04

Net (loss) income per common unit	$	(2.84	)	$	(0.36	)	$	(0.37	)	$	0.40		$	1.01

Weighted average number of common units		66,125			63,193			63,854			58,038			57,856


	Nine Months ended September 30,						Year ended December 31,
	2011			2010			2010			2009			2008
	(in thousands)
Balance Sheet Data (at period end):
Total assets	$	2,017,900		$	1,927,145		$	1,906,993		$	1,867,412		$	2,013,665
Long term debt (includes $0 and $567 as of September 30, 2011 and 2010, respectively and $546, $628 and $704 bond premium as of December 31, 2010, 2009 and 2008, respectively)		904,525			582,757			592,736			852,818			821,119
Total members’ capital		906,228			1,196,850			1,154,757			860,026			1,037,958
Cash Flow Data:
Net cash provided by operating activities	$	122,789		$	94,489		$	123,598		$	141,318		$	89,924
Net cash used in investing activities		(299,114	)		(111,596	)		(156,730	)		(70,967	)		(198,855	)
Net cash provided by (used in) financing activities		169,929			74,196			48,370			(89,343	)		99,950
Other Financial Data:
Total segment gross margin(3)(4)	$	190,484		$	165,683		$	227,389		$	219,450		$	254,144
EBITDA(5)		(76,811	)		72,828			108,427			137,327			174,752
Adjusted EBITDA(5)		153,618			146,313			199,528			201,095			242,009
Maintenance capital expenditures	$	11,111		$	6,370		$	9,563		$	9,728		$	11,769
Expansion Capital Expenditures		203,576			101,232			120,941			61,424			169,056

Total Capital Expenditures	$	214,687		$	107,602		$	130,504		$	71,152		$	180,825

(1)	Exclusive of operations and maintenance and depreciation, amortization and impairment shown separately.

(2)	For more information, please read Note 13, “Discontinued Operations,” in our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010.

(3)

Excludes results attributable to our crude oil pipeline and related assets for the year ended December 31, 2009; which are classified as discontinued operations, as discussed in Note 13, “Discontinued Operations,” in our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010.

(4)

To measure the overall financial impact of our contract portfolio, we use total segment gross margin, which is the sum of our operating segments’ gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas, oil and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities. The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii) amortization expense relating to the option component of our commodity derivative instruments and (iii) unrealized mark-to-market gain or loss on our commodity derivative instruments that have not been designated as cash flow hedges. Total segment gross margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Our use of total gross margin, and the underlying methodology in

excluding certain charges, is not necessarily an indication of the results of operations that may be expected in the future, or that we will not, in fact, incur such charges in future periods. The following table reconciles total gross margin to operating income, which is the most directly comparable GAAP financial performance measure:


	Nine Months ended September 30,					Year ended December 31,
	2011			2010		2010		2009			2008
	(in thousands)
Reconciliation of total segment gross margin to operating income:
Operating income	$	(109,752	)	$	26,767	$	45,777	$	72,355		$	105,703
Add:
Operations and maintenance expenses		46,953			38,337		53,487		51,477			53,824
Depreciation, amortization and impairment		56,143			46,002		62,572		56,975			52,916
General and administrative expenses		34,530			31,311		40,347		39,511			45,571
Taxes other than income		4,029			3,658		4,726		3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates		158,581			19,788		20,480		(4,600	)		(6,889	)

Total segment gross margin	$	190,484		$	165,863	$	227,389	$	219,450		$	254,144

(5)

We define EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation and amortization expense. We determine adjusted EBITDA by adding to EBITDA (i) the amortization expenses attributable to commodity derivative options, (ii) distributions from unconsolidated affiliates, (iii) any loss on refinancing of unsecured debt, (iv) equity-based compensation expenses, (v) equity in loss or subtracting equity in earnings from unconsolidated affiliates, (vi) unrealized loss or subtracting unrealized gain from commodity risk management activities, (vii) impairment expenses and (viii) other non-cash operating items. We revised our calculation of adjusted EBITDA commencing in the second quarter of 2011 to the formula above in order to more closely resemble that of many of our peers in terms of measuring our ability to generate cash. Subsequent to the third quarter of 2011, we revised our presentation of EBITDA to exclude impairment expenses and instead add back impairment expenses in Adjusted EBITDA.

External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or adjusted EBITDA, and our management uses adjusted EBITDA, as a supplemental financial measure to assess:

•

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

•

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

•

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

•

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

EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to our lenders and used to compute financial covenants under our revolving credit facility. Neither EBITDA nor adjusted

EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP. The following table reconciles EBITDA and Adjusted EBITDA to net income (loss), which is the most directly comparable GAAP financial performance measure:


	Nine Months ended September 30,						Year ended December 31,
	2011			2010			2010			2009			2008
	(in thousands)
Reconciliation of EBITDA and adjusted EBITDA to net income (loss):
Net (loss) income	$	(163,565	)	$	(15,073	)	$	(8,681	)	$	23,158		$	58,213
Add:
Depreciation and amortization(6)		51,143			46,002			62,572			57,539			50,312
Interest and other financing costs		34,450			41,239			53,605			55,836			64,978
Provisions for income taxes		1,161			660			931			794			1,249

EBITDA		(76,811	)		72,828			108,427			137,327			174,752
Add:
Amortization of commodity derivative options		22,069			24,211			32,378			36,950			32,842
Distributions from unconsolidated affiliates		20,329			19,554			25,955			29,684			25,830
Loss on refinancing of unsecured debt		18,233			—			—			—			—
Equity-based compensation		9,184			7,849			10,388			8,252			7,789
Equity in loss (earnings) from unconsolidated affiliates		158,581			19,788			20,480			(4,600	)		(6,889	)
Unrealized loss (gain) from commodity risk management activities		(2,695	)		150			584			(4,131	)		2,759
Impairment		5,000			—			—			—			2,842
Other non-cash operating items		(272	)		1,933			1,316			(2,387	)		2,084

Adjusted EBITDA	$	153,618		$	146,313		$	199,528		$	201,095		$	242,009

(6)	Includes activity related to the discontinued operations of the crude oil pipeline and related assets discussed in Note 13, “Discontinued Operations,” in our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010.

An investment in our common units involves risk. You should carefully read the risk factors included under the caption “Risk Factors” beginning on page 6 of the accompanying prospectus and the risk factors included in Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, together with all of the other information included or incorporated by reference in this prospectus supplement and the accompanying prospectus. If any of these risks were to occur, our business, financial condition, results of operations or prospects could be materially adversely affected. In such case, the trading price of our common units could decline, and you could lose all or part of your investment.

We intend to use the net proceeds from this offering (and the net proceeds from any exercise of the underwriters’ option to purchase additional common units) to repay a portion of the outstanding indebtedness under our revolving credit facility.

At December 31, 2011, an aggregate of approximately $385 million of borrowings was outstanding under our revolving credit facility. The weighted average interest rate on borrowings under our revolving credit facility was 5.60% at December 31, 2011. Our revolving credit facility matures on June 10, 2016. We use borrowings under our revolving credit facility for capital projects, acquisitions, hedging, working capital and general corporate purposes, and we anticipate that we will use increased borrowing availability under our revolving credit facility after this offering for such purposes.

The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of certain of the underwriters are lenders under our revolving credit facility and, accordingly, will receive a portion of the proceeds from this offering pursuant to the repayment of borrowings under such credit facility. Please read “Underwriting.”

The following table sets forth our consolidated cash and cash equivalents and our consolidated capitalization as of September 30, 2011 on:

The following table should be read together with our financial statements and the notes thereto that are incorporated by reference into this prospectus supplement for additional information regarding us. Please read “Where You Can Find More Information.”

Our common units trade on the Nasdaq Global Select Market under the symbol “CPNO.” On January 12, 2012, the closing sales price of our common units, as reported by the Nasdaq Global Select Market, was $35.36 per common unit. As of December 31, 2011, there were 98 holders of record of our common units.

The following table presents the intraday quarterly high and low sales prices for our common units, as reported by the Nasdaq Global Select Market as well as the amount of quarterly cash distributions per common unit declared per quarter.

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. Please read (i) “Material Tax Consequences” in the accompanying prospectus for a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units and (ii) “Risk Factors—Tax Risks to Common Unitholders” in the accompanying prospectus and “Tax Risks to Common Unitholders” in our Annual Report on Form 10-K for the year ended December 31, 2010, which is incorporated by reference into this prospectus supplement, for a discussion of the federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units. You are urged to consult with your own tax advisor about the federal, state, local and foreign tax consequences peculiar to your circumstances.

We estimate that if you purchase common units in this offering and own them through December 31, 2014, then you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. If you continue to own common units purchased in this offering after that period, the ratio of allocable taxable income to cash distributions applicable to you may be higher. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make quarterly distributions of $0.575 on all units and other assumptions with respect to the timing and amount of capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we follow and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

Under current law, the highest marginal federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on investment income earned by individuals, estates and trusts is scheduled to apply for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income or (2) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case).

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) 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 U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million 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.

Ownership of common units by tax-exempt entities, regulated investment companies and non-U.S. investors raises issues unique to such persons. Please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors” on page 52 of the accompanying prospectus.

Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, Deutsche Bank Securities Inc., and Wells Fargo Securities, LLC are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which is or will be filed as an exhibit to our current report on Form 8-K and incorporated by reference in this prospectus supplement and the accompanying prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

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

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.

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 $0.792 per unit. After the offering, the representatives may change the offering price and other selling terms. Sales of common units made outside of the United States may be made by affiliates of the underwriters.

The expenses of the offering that are payable by us are estimated to be $581,000 (excluding underwriting discounts and commissions).

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 750,000 additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 5,000,000 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 common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

We and certain of our affiliates, including our directors and executive officers have agreed not to, without the prior written consent of Barclays Capital Inc., during the period ending 60 days after the date of this prospectus supplement:

The restrictions described in the paragraph above do not apply to, among other things:

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

The representatives 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 Exchange Act:

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 Nasdaq Global Select Market or otherwise and, if commenced, may be discontinued at any time.

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 representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

In connection with the offering, underwriters and selling group members may engage in passive market making transactions in the common units on the NASDAQ Global Select Market in accordance with Rule 103 of Regulation M under the Exchange Act during the period before the commencement of offers or sales of common

units and extending through the completion of distribution. A passive market maker must display its bids at a price not in excess of the highest independent bid of the security. However, if all independent bids are lowered below the passive market maker’s bid that bid must be lowered when specified purchase limits are exceeded.

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 underwriters and/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 representatives on the same basis as other allocations.

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 approved and/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.

If you purchase common units offered in this prospectus supplement and the accompanying prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus supplement and the accompanying prospectus.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and their affiliates have performed investment and commercial banking and advisory services for us and our affiliates from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. As described in “Use of Proceeds,” some of the net proceeds of this offering may be used to repay borrowings under our secured credit facility. Because affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC, Morgan Stanley & Co. LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co., RBC Capital Markets, LLC and Morgan Keegan & Company, Inc. are lenders under our secured credit facility, certain of such underwriters or their affiliates may receive more than 5% of the proceeds of this offering (excluding underwriting discounts and commissions). Nonetheless, in accordance with the Financial Industry Authority Rule 5121, the appointment of a qualified independent underwriter is not necessary in connection with this offering because the common units are interests in a direct participation program. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments including serving as counterparties to certain derivative and hedging arrangements, and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognized collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(1) if we are a CIS and is marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

(2) otherwise, if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(3) in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

The consolidated financial statements of Copano Energy, L.L.C. and subsidiaries incorporated in this prospectus supplement by reference from the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 and the effectiveness of Copano Energy, L.L.C. and its subsidiaries internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference. Such financial statements 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 Bighorn Gas Gathering, L.L.C. and Fort Union Gas Gathering, L.L.C. incorporated in this prospectus by reference from Copano Energy, L.L.C.’s Annual Report on Form 10-K for the year ended December 31, 2010 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports, which are incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information that we file electronically with the SEC.

We also make available free of charge on our website, at www.copanoenergy.com, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 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 on our website, other than the documents listed below, is not incorporated by reference into this prospectus supplement.

We “incorporate by reference” information into this prospectus supplement, 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 supplement, except to the extent it is updated and superseded by information contained in this prospectus supplement. The information we file later with the SEC will automatically update and supersede information in this prospectus supplement. You should not assume that the information in this prospectus supplement is current as of any date other than the date on the front page of this prospectus supplement.

We incorporate by reference the documents listed below, excluding any information furnished pursuant to Item 2.02 or 7.01 in any Current Report on Form 8-K (or corresponding information furnished under Item 9.01 or included as an exhibit):

All documents that we subsequently file pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act, and that are deemed “filed” prior to the termination of this offering, shall be deemed to be incorporated by reference into this prospectus supplement.

You may obtain any of the documents incorporated by reference in this prospectus supplement from the SEC through the SEC’s website at the address provided above. We will provide you a copy of any or all of the information that has been incorporated by reference in this prospectus supplement (including exhibits to those documents specifically incorporated by reference in this document), at no cost, upon your written or oral request to us at the following address or telephone number:

This prospectus supplement relates to our effective registration statement on Form S-3 (Registration No. 333-162821) filed with the SEC. This prospectus supplement does not contain all of the information set forth in the registration statement and the exhibits to the registration statement. Statements about the contents of contracts or other documents contained in this prospectus supplement or in any other filing to which we refer you are not necessarily complete. You should review the actual copy of these documents filed as an exhibit to the registration statement or such other filing. You may obtain a copy of the registration statement and the exhibits filed with it from the SEC or us at any of the locations listed above.

We may offer, from time to time, the following securities in one or more transactions, classes or series and in amounts, at prices and on terms to be determined by market conditions at the time of our offerings:

Copano Energy Finance Corporation may act as co-issuer of the debt securities. If a series of debt securities is guaranteed, such series will be guaranteed by all of Copano Energy, L.L.C.’s wholly owned subsidiaries other than “minor” subsidiaries (except Copano Energy Finance Corporation) as such term is interpreted in securities regulations governing financial reporting for guarantors.

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 and the general manner in which we will offer the securities. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. This prospectus may not be used to consummate sales of securities unless accompanied by a prospectus supplement.

You should carefully read this prospectus and any prospectus supplement before you invest. You should also 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.

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.

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 described under “Risk Factors” beginning on page 6 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 state securities commission 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.

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, or the “SEC” or “Commission.” In making your investment decision, you should rely only on the information contained in or incorporated by reference in this prospectus and any prospectus supplement. 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 jurisdiction where the offer is not permitted.

You should not assume that the information contained in this prospectus or any prospectus supplement, as well as the information that we have previously filed with the SEC that is incorporated by reference into this prospectus or any prospectus supplement, is accurate as of any date other than the date of such document. Our business, financial condition, results of operations and prospects may have changed since those dates.

This prospectus is part of a registration statement on Form S-3 that we and Copano Energy Finance Corporation have filed with the SEC using a “shelf” registration process. Under this shelf registration process, we may from time to time offer and sell the securities described in this prospectus in one or more offerings. This prospectus describes the general terms of these securities and the general manner in which we will offer the securities. Each time we offer securities, we will provide you with this prospectus and a prospectus supplement that will describe, among other things, the specific amounts and prices of the securities being offered and the terms of the offering.

The prospectus supplement may include additional risk factors or other special considerations applicable to those securities and may also add, update or change information contained 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 carefully read this prospectus, including the “Risk Factors,” and any attached prospectus supplement relating to the securities offered to you, together with the additional information described under “Where You Can Find More Information,” 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.

We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information that we file electronically with the SEC.

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 on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 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 on our website is not incorporated by reference into this prospectus.

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 to the extent it is updated and superseded by information contained in this prospectus. The information we file later with the SEC will automatically update and supersede information in this prospectus. 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.

We incorporate by reference the documents listed below (excluding any information furnished pursuant to Item 2.02, 7.01 or 9.01 on any Current Report on Form 8-K):

All documents that we file pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), and that are deemed “filed,” prior to the termination of all offerings under this shelf registration statement are incorporated by reference into this prospectus.

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. We will provide you a copy of any or all of the information that has been incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, upon your written or oral request to us at the following address or telephone number:

Certain matters discussed in this prospectus and the documents we incorporate by reference include “forward-looking” statements. Statements that are not historical facts and instead 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 terms such as “may,” “believe,” “expect,” “anticipate,” “estimate” or “continue,” or similar words, and 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 perceptions 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 differ materially from what is expressed, implied or forecast in forward-looking statements. Any differences could result from a number of factors, including:

This prospectus and the documents incorporated by reference include cautionary statements identifying important factors that could cause our actual results to differ materially from our expectations, including in conjunction with forward-looking statements described above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any accompanying prospectus supplement 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. Such 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.

We are an energy company engaged in the business of providing midstream services to natural gas producers, including natural gas gathering, compression, dehydration, treating, marketing, transportation, processing, conditioning and fractionation services. Our assets are located in Oklahoma, Texas, Wyoming and Louisiana and include approximately 6,200 miles of active natural gas gathering and transmission pipelines and seven natural gas processing plants, with over one billion cubic feet per day of combined processing capacity. In addition to our natural gas pipelines, we operate 200 miles of NGL pipelines.

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. 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 are limited to co-issuing our debt securities and activities incidental to its role as a co-issuer.

Our principal executive offices are located at 2727 Allen Parkway, Suite 1200, Houston, Texas 77019. Our telephone number at our principal executive offices is (713) 621-9547.

For additional information about our business, properties and financial condition, please read “Where You Can Find More Information.”

Certain of our subsidiaries, which we refer to as the “subsidiary guarantors” in this prospectus, may fully and unconditionally guarantee our payment obligations under any series of debt securities offered using this prospectus. Financial information concerning our subsidiary guarantors and any non-guarantor subsidiaries will, to the extent required by SEC rules and regulations, be included in our consolidated financial statements filed as part of our periodic reports pursuant to the Exchange Act.

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.

We may not have sufficient cash after establishment of cash reserves to pay cash distributions at the current level.

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

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:

If we decrease distributions, the market price for our units may be adversely affected.

A decrease in our cash flow will reduce the amount of cash we have available for distribution to our unitholders.

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

To the extent that we make acquisitions in the future and our acquisitions do not perform as expected, our future financial performance may be negatively impacted.

Our business strategy includes making acquisitions that we anticipate would increase the cash available for distribution to our unitholders. As a result, from time to time, we evaluate and pursue assets and businesses that we believe complement our existing operations or expand our operations into new regions where our growth strategy can be applied. We cannot assure you that we will be able to complete acquisitions in the future or achieve the desired results from any acquisitions we do complete. In addition, failure to successfully assimilate our acquisitions could adversely affect our financial condition and results of operations.

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. Because of these risks and challenges, even when we make acquisitions that we believe will increase our ability to distribute cash, those acquisitions may nevertheless reduce our cash from operations on a per unit basis. This could result in lower distributions to our common unitholders and could impair our ability to comply with financial covenants under our debt agreements. Our capitalization and results of operations may change significantly following an acquisition, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

We generally assume the liabilities of entities that we acquire and may assume certain liabilities relating to assets that we acquire, including unknown and contingent liabilities. We perform due diligence in connection with our acquisitions and attempt to verify the representations of the sellers, but there may be pending, threatened, contemplated or contingent claims related to environmental, title, regulatory, litigation or other

matters of which we are unaware. We may have indemnification claims against sellers for certain of these liabilities, as well as for disclosed liabilities, but our indemnification rights generally will be limited in amount and duration. Our right to indemnification also will be limited, as a practical matter, to the creditworthiness of the indemnifying party. If our right to indemnification is inadequate to cover the obligations of an acquired entity or relating to acquired assets, or if our indemnifying seller is unable to meet its obligations to us, our liability for such obligations could materially adversely affect our cash flow, operations and financial condition.

We may not be able to fully execute our business strategy if we encounter illiquid capital markets.

Our business strategy contemplates pursuing acquisitions and capital projects, both in our existing areas of operations and in new regions where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions or projects that we believe will present opportunities to pursue our growth strategy.

We will require substantial new capital to finance strategic acquisitions or to complete significant organic expansion or greenfield projects. Any limitations on our access to capital will impair our ability to execute our growth strategy. If the cost of capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include market conditions and offering or borrowing costs such as interest rates or underwriting discounts.

Illiquid capital markets could also limit investment and development by third parties, such as producers and end-users, which could indirectly affect our ability to fully execute our business strategy.

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

We have substantial indebtedness. As of June 30, 2009 and in addition to liabilities we incurred related to our risk management activities, we had total indebtedness of $852 million, including our senior unsecured notes and our revolving credit facility.

At June 30, 2009, available borrowing capacity under our revolving credit facility was approximately $280 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:

If we are unable to meet our debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness, in which case our lenders could require us to suspend cash distributions, or seek additional equity capital or sell assets. We may be unable to obtain such refinancing or equity capital, or to 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 unsecured notes contains various covenants that limit our ability and the ability of specified subsidiaries to, among other things:

Our revolving credit facility contains similar covenants, as well as covenants that require us to maintain specified financial ratios and satisfy other financial conditions. The restrictive covenants in our indentures and our revolving credit facility 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 or conduct operations.

If we are unable to comply with our debt covenants, it could result in defaults under the terms of our indentures or our revolving credit facility and acceleration of our debt and other financial obligations. If we were unable to repay those obligations, our lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against any collateral.

In addition, Fort Union Gas Gathering, L.L.C. (“Fort Union”), in which we own a 37.04% interest, has debt outstanding under an agreement that includes, among other customary covenants and events of default, a limitation on its ability to make cash distributions. Fort Union can distribute cash to its members only if its ratio of net operating cash flow to debt service is not less than 1.25 to 1.00. If Fort Union fails to comply with this covenant, it would be prohibited from distributing cash to us, which would adversely affect our cash flow.

Our ability to obtain funding under our revolving credit facility could be impaired by conditions in the financial markets.

We operate in a capital-intensive industry and rely on our revolving credit facility to finance a significant portion of our capital expenditures. Our ability to borrow under our revolving credit facility is subject to conditions in the financial markets, including the solvency of institutional lenders. Specifically, we would be unable to obtain adequate funding under our revolving credit facility if:

If we are unable to access funds under our revolving credit facility, we would need to meet our capital requirements using other sources. Depending on economic conditions, alternative sources of liquidity may not be available on acceptable terms. If the cash generated from our operations or the funds we are able to obtain under our revolving credit facility or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon capital projects or other business opportunities, which could have a material adverse effect on our results of operations and financial condition.

Our ability to obtain financing from sources other than our revolving credit facility is subject to conditions in the credit and capital markets.

If we need to raise capital from a source other than our revolving credit facility, we cannot be certain that additional capital will be available to the extent required and on acceptable terms. Global market and economic conditions have been volatile, and the timing of an economic recovery remains uncertain. The availability and cost of debt and equity capital are subject to general economic conditions and prevailing perceptions about the stability of financial markets and the solvency of counterparties. Adverse changes in these factors are likely to result in higher interest rates and deterioration in the availability and cost of debt and equity financing.

If capital on acceptable terms is unavailable to us, we may be unable to fully execute our growth strategy, otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operations and financial condition.

We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonpayment and nonperformance by counterparties could adversely affect our cash flows, results of operations and financial condition.

Risks of nonpayment and nonperformance by our counterparties are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity, all of which are subject to adverse changes in commodity prices and economic and market conditions. Since the most recent economic downturn, some of our customers have experienced a combination of lower cash flow due to commodity prices, reduced borrowing bases under reserve-based credit facilities and reduced availability of debt or equity financing. These factors may result in a significant reduction in our customers’ liquidity and ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own credit, operating and regulatory risks, which increases the risk that they may default on their obligations to us.

Any increase in nonpayment and nonperformance by our counterparties, either as a result of financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

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

Our cash flow and profitability are affected by prevailing NGL and natural gas prices, and we are subject to significant risks due to fluctuations in commodity prices. 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 nine months ended

September 30, 2009, the Houston Ship Channel natural gas index price ranged from a high of $5.26 per MMBtu to a low of $2.69 per MMBtu. Based on average monthly Mt. Belvieu prices and our weighted-average product production mix in Texas during this period, NGL prices ranged from a high of approximately $36.72 per barrel to a low of approximately $25.46 per barrel.

We derive a majority of our gross margin from contracts with terms that are commodity price sensitive. As a result, our cash flow and profitability depend to a significant extent on the prices at which we buy and sell natural gas and at which we sell NGLs and condensate. The markets and prices for natural gas and NGLs depend upon many factors beyond our control. These factors include supply and demand for oil, natural gas, liquefied natural gas (“LNG”), nuclear energy, coal and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of natural gas we gather and process. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our hedging strategies cannot offset volume risk and may not be sufficient to offset price volatility risk. In any event, our commodity derivatives do not cover all of our throughput volumes. Moreover, commodity derivatives are subject to inherent risks, which we describe below under “—Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.”

Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.

Our operations expose us to fluctuations in commodity prices, and our revolving credit facility exposes us to fluctuations in interest rates. We use derivative financial instruments to reduce our sensitivity to commodity prices and interest rates, and the degree of our exposure is related largely to the effectiveness and scope of our hedging activities. We have hedged only portions of our variable-rate debt and expected natural gas and condensate supply, NGL production and natural gas requirements. We continue to have direct interest rate and commodity price risk with respect to the unhedged portions.

Our ability to enter into new derivative instruments is subject to general economic and market conditions. The markets for instruments we use to hedge our commodity price and interest rate exposure generally reflect conditions in the underlying commodity and debt markets, and to the extent conditions in underlying markets are unfavorable, our ability to enter into new derivative instruments on acceptable terms will be limited. In addition, to the extent we hedge our commodity price and interest rate risks using swap instruments, we will forego the benefits of favorable changes in commodity prices or interest rates.

Even though monitored by management, our hedging activities may fail to protect us and could reduce our cash flow and profitability. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors:

Our financial statements may reflect gains or losses arising from exposure to commodity prices or interest rates for which we are unable to enter into fully economically effective hedges. In addition, the standards for cash flow hedge accounting are rigorous. Even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective cash flow hedges for accounting purposes. Our earnings could be subject to increased volatility to the extent our derivatives do not continue to qualify as cash flow hedges, and, if we assume derivatives as part of an acquisition, to the extent we cannot obtain or choose not to seek cash flow hedge accounting for the derivatives we assume.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA (defined below) contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or “CFTC,” to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC urged Congress to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products, and to bring the entire over-the-counter (“OTC”) derivatives marketplace under CFTC regulation. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department has proposed legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. A recent house bill would give the CFTC power to set position limits and to regulate commodity swaps. Although it is not possible at this time to predict whether or when Congress may act on this or other derivatives legislation or how any climate change bill approved by the U.S. Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our flexibility in hedging risks associated with our business or on the cost of our hedging activity.

Because of the natural decline in production from existing wells in our operating regions, our future success depends on our ability to continually obtain new sources of natural gas supply, which depends in part on certain factors beyond our control. 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 fields and wells, from 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 volumes on our pipeline systems and at our processing plants, we must continually connect new supplies of natural gas and attract new customers to our gathering and transmission lines. The primary factors affecting our ability to do so include the level of successful drilling activity near our gathering systems and our ability to compete for the attachment of such additional volumes to our systems.

Fluctuations in energy prices can greatly affect drilling and 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 drilling and production decisions, which are affected by, among other things, prevailing and projected energy prices, drilling costs, rig availability, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

The current pricing environment, particularly in combination with the constrained capital and credit markets and overall economic downturn, has resulted in a decline in drilling activity by some producers in each of our segments. Lower drilling levels over a sustained period would have a negative effect on the volumes of natural gas we gather and process. We cannot use hedging to offset the potential effects of declining volumes.

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 segment include Enterprise Products Partners, Lobo Pipeline Company, Kinder Morgan Texas Pipeline, or KMTP, DCP Midstream, Crosstex Energy, ExxonMobil, Houston Pipeline Company, Targa Resources, Atlas Pipeline and Devon Energy. The primary competitors in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, ONEOK Field Services, Enogex, Enerfin, Hiland Partners and MarkWest. The primary competitors in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy and Western Gas Resources. A number of our competitors are larger organizations than we are.

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

We rely on third-party pipelines and other facilities in providing service to our customers. If one or more of these pipelines or facilities were to become capacity- constrained or unavailable, our cash flows, results of operations and financial condition could be adversely affected.

Our ability to contract for natural gas supplies in the Texas region will often depend on our ability to deliver gas to our Houston Central plant and downstream markets, and we rely on KMTP’s Laredo-to-Katy pipeline to transport natural gas from our South Texas systems to the Houston Central plant. For the six months ended June 30, 2009, approximately 46% of the total natural gas delivered by our Texas segment was delivered to KMTP, and approximately 80% of the natural gas volumes processed or conditioned at our Houston Central plant was delivered to the plant through the KMTP Laredo-to-Katy pipeline.

If KMTP’s pipeline were to become unavailable for any reason, the volumes transported to our Houston Central plant would be reduced substantially, and our revenues and operating income from our Texas processing business would be adversely affected. In addition, much of the natural gas we gather in South Texas contains NGLs that must be removed in order to meet downstream market quality specifications. If we were unable to ship such natural gas to our Houston Central plant, we would need to arrange for an alternate means of removing NGLs and transport through other pipelines. Alternatively, we might be required to lease smaller treating and processing facilities so that we could treat and condition or process natural gas as needed to meet pipeline quality specifications.

We rely on ONEOK Hydrocarbon to take delivery of NGLs from several of our processing plants. We believe that fractionation facilities to which ONEOK Hydrocarbon delivers NGLs, as well as other fractionation facilities on which we depend, are subject to increasing capacity constraints due to higher NGL production in the Rocky Mountains and Mid-Continent regions. If ONEOK Hydrocarbon or the related downstream fractionation facilities were to become unavailable, we would have to run the affected plants in a reduced operating mode and make arrangements to re-route a portion of the natural gas we receive for processing to third-party plants, as well as make arrangements to transport NGLs to market by truck.

We also depend on other third-party processing plants, pipelines and other facilities to provide our customers with processing, delivery or transportation options. Like us, third-party service providers are subject to risks inherent in the midstream business, including capacity constraints, and natural disasters and operational, mechanical or other hazards. Because we do not own or operate KMTP’s, ONEOK Hydrocarbon’s, or any of these other pipelines and facilities, their continuing operation is not within our control.

If any of these pipelines and other facilities becomes unavailable or limited in its ability to provide services on which we depend, our revenues and cash flow could be adversely affected. We would likely incur higher fees or other costs in arranging for alternatives, and a prolonged interruption or reduction of service on KMTP or ONEOK could hinder our ability to contract for additional gas supplies.

We generally do not obtain reservoir engineering reports evaluating 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 reservoir engineering reports evaluating 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, which could have a material adverse effect on our business, financial condition and our ability to make cash distributions to you.

Federal, state or local regulatory measures could adversely affect our business.

Our pipeline transportation and gathering systems are subject to federal, state and local regulation. Most of our natural gas pipelines are gathering systems that are considered non-utilities in the states in which they are located. The Natural Gas Act (“NGA”) leaves any economic regulation of natural gas gathering to the states. Texas, Oklahoma and Wyoming, the states in which our pipeline facilities are located, do not currently regulate non-utility gathering fees.

Our gathering fees and our terms and conditions of service may nonetheless be constrained through state anti-discrimination laws. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities. Natural gas producers, shippers and other affected parties may file complaints with state

regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with regard to rates and terms of service. A successful complaint, or new laws or regulatory rulings related to gathering, could increase our costs or require us to alter our gathering charges, and our business, and therefore, results of operations and financial condition could be adversely affected. Other state laws and regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for gathering, purchase, processing and sale, including state regulation of production rates and maximum daily production allowables from gas wells.

Our intrastate natural gas transmission pipeline and several of our gathering systems in Texas are subject to regulation as gas utilities by the Texas Railroad Commission (“TRRC”). The TRRC’s jurisdiction over these pipelines extends to both rates and pipeline safety. The rates we charge for transportation services in Texas generally are deemed just and reasonable under Texas law unless challenged in a complaint. A successful complaint, or new state laws or regulatory rulings related to natural gas utilities, could increase our costs or require us to alter our service charges.

To the extent that our intrastate transmission pipeline in Texas transports natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to regulation by the Federal Energy Regulatory Commission (“FERC”) pursuant to Section 311 of the Natural Gas Policy Act of 1978. Section 311 requires, among other things, that rates for such interstate service, which may be established by FERC or the applicable state agency, be “fair and equitable,” and permits the FERC to approve terms and conditions of service. If our Section 311 rates are successfully challenged, if we are unable to include all of our costs in the cost of service approved in a future rate case, if FERC changes its regulations or policies, or establishes more onerous terms and conditions applicable to Section 311 service, our margins relating to this activity would be adversely affected.

We also have transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, we are subject to FERC requirements related to use of the interstate capacity. Any failure on our part to comply with the FERC’s regulations or an interstate pipeline’s tariff could result in the imposition of administrative civil and criminal penalties.

We have interests in three NGL pipelines, all of which are located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged, however. Should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow. The price at which we buy and sell natural gas and NGLs is currently not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. The FERC and the CFTC hold substantial enforcement authority under the anti-market manipulation laws and regulations, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

The FERC has also promulgated additional market-monitoring and reporting regulations intended to increase the transparency of wholesale energy markets, protect the integrity of such markets and improve the FERC’s ability to assess market forces and detect market manipulation. One such set of regulations, FERC Order No. 720, requires certain major non-interstate pipelines to post daily information on each such pipeline’s internet

web site concerning capacity and scheduled flow information. Order No. 720 is currently pending rehearing before FERC. FERC has requested supplemental comments on a number of issues and has proposed revisions to its Order No. 720 regulations. The FERC has also issued a Notice of Proposed Rulemaking proposing to increase the frequency, level of detail and mode of contract reporting by intrastate Section 311 natural gas pipelines. We cannot predict the ultimate outcome of these proceedings. Additionally, the FERC has imposed new rules requiring certain wholesale purchasers and sellers of physical natural gas to report aggregated annual volume and other information beginning in 2009. These and other transparency rules may subject certain of our operations to additional reporting requirements, which could subject us to further costs and administrative burdens.

These and other new laws and regulations or any administrative or judicial re-interpretations of existing laws, regulations or agreements could require us to incur increased costs and administrative burdens, and our business, results of operations and financial condition could be adversely affected. For instance, on February 19, 2008, the U.S. Supreme Court agreed to hear arguments in a lawsuit, Montana v. Wyoming, filed by the State of Montana against Wyoming over water rights in two rivers that flow through both states. Montana is asserting that Wyoming is using too much water from the Tongue and Powder Rivers pursuant to the Yellowstone River Compact, an agreement that both states entered into in 1950 addressing how the states may share water from the Yellowstone River and its tributaries, including the Tongue and Powder Rivers. A critical element of Montana’s argument is that the Compact applies to groundwater and, among other things, that Wyoming’s permitting of coal bed methane production, which involves the pumping of large quantities of groundwater, is depleting the waters of the two rivers to the detriment of Montana and its water users and in violation of the Compact. Wyoming’s position is that the Compact does not address groundwater. Among other things, Montana asks the High Court to declare the rights of Montana to water from these two rivers pursuant to the Compact and to issue a decree commanding Wyoming in the future to deliver the waters of these two rivers to Montana in accord with the Compact. This lawsuit has only recently been accepted for review by the U.S. Supreme Court and no substantive determination has yet been made regarding the use of waters from these two rivers, including the associated groundwater. Any decision made by the U.S. Supreme Court as a result of this case that effectively limits the amount of groundwater pumped in connection with coal bed methane production in Wyoming may have significant adverse impacts on the volume of production by coal bed methane producers in affected areas of Wyoming and, correspondingly, on gathering services that Bighorn Gas Gathering, L.L.C. (“Bighorn”) and Fort Union provide.

We must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of our business plans. For example, in order to carry out our acquisition of the McMullen Lateral pipeline, Transcontinental Gas Pipeline Corp. (“Transco”), a subsidiary of The Williams Companies, Inc., must obtain a FERC order allowing abandonment of the facilities by Transco, as well as various other related FERC authorizations. The abandonment application is subject to protests filed by third parties and there is no guarantee that FERC will grant the application and the authorizations requested therein. Moreover, there is no guarantee that, if granted, such authorizations will be timely or will be free from potentially burdensome conditions.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas and NGL services we provide.

On June 26, 2009, the U.S. House of Representatives approved the adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESAwould establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% (from 2005 levels) by 2050. Regulated entities under ACESA would include producers of petroleum based fuels, including refiners of oil, fractionators of NGLs and natural gas distribution companies. Under ACESA, most regulated sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances

authorized each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The Senate is considering climate change legislation during the fall of 2009.

In addition, on April 17, 2009, the U.S. Environmental Protection Agency, or “EPA,” issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane and other GHGs presented an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the Earth’s atmosphere. Once finalized, EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Also, two appellate courts recently took actions that allowed two lawsuits to resume to decide on the merits whether certain business entities could be held liable under common law actions with respect to those entities’ emission of greenhouse gases. With regard to one of the proceedings, on September 21, 2009, the U.S. Court of Appeals for the Second Circuit reinstated a lawsuit filed by several state attorneys general and others against five of the largest U.S. electric utility companies alleging that those companies have created a public nuisance due to their emissions of carbon dioxides. In the other proceeding, on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit allowed a lawsuit to resume wherein a putative class of property owners along the Mississippi Gulf Coast have alleged that an array of electric utilities and fossil fuel and chemical companies were negligent or had created trespass or nuisance conditions through their emissions of greenhouse gases that added to the ferocity of Hurricane Katrina in 2005.

Although it is not possible at this time to predict if and when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA or what effect, if any, the recent decisions permitting the common law negligence, trespass and/or nuisance lawsuit to proceed against certain utilities and fossil fuel and chemical companies may have on the oil and gas industry, any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions, as well as future climate change litigation against us or our customers for GHG emissions, could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the natural gas and NGL services we provide.

A change in the characterization of some of our assets by federal, state or local regulatory agencies could adversely affect our business.

Section 1(b) of the NGA provides that the FERC’s jurisdiction does not extend to facilities used for the production or gathering of natural gas. “Gathering” is not specifically defined by the NGA or its implementing regulations, and there is no bright-line test for determining the jurisdictional status of pipeline facilities. Although some guidance is provided by case law, the process of determining whether facilities constitute gathering facilities for purposes of regulation under the NGA is fact-specific and subject to regulatory change. Additionally, our construction, expansion, extension or alteration of pipeline facilities may involve regulatory, environmental, political and legal uncertainties, including the possibility that physical changes to our pipeline systems may be deemed to affect their jurisdictional status.

The distinction between FERC-regulated interstate natural gas transmission services and federally unregulated gathering services has been the subject of litigation, as has been the line between intrastate and interstate transportation services. Thus, the classification and regulation of some of our natural gas gathering facilities and our intrastate transportation pipeline may be subject to change based on future determinations by

the FERC and/or the courts. Should any of our natural gas gathering or intrastate facilities be deemed to be jurisdictional under the NGA, we could be required to comply with numerous federal requirements for interstate service, including laws and regulations governing the rates charged for interstate transportation services, the terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the initiation and discontinuation of services, the monitoring and posting of real-time system information and many other requirements. Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders could result in substantial penalties and fines. It is also possible that our gathering facilities could be deemed by a relevant state commission or court, or by a change in law or regulation, to constitute intrastate pipelines subject to general state law and regulation of rates and terms and conditions of service. A change in jurisdictional status through litigation or legislation could require significant changes to the rates, terms and conditions of service on the affected pipeline, could increase the expense of providing service and adversely affect our business.

The distinction between FERC-regulated common carriage of NGLs, and the non-jurisdictional intrastate transportation of NGLs, has also been the subject of litigation. The FERC, under the ICA, the Energy Policy Act of 1992 and the rules and orders promulgated thereunder, regulates the tariff rates for interstate NGL transportation and these rates must be filed with the FERC. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. To the extent any of our NGL assets are subject to the jurisdiction of the FERC, the FERC’s rate-making methodologies could limit our ability to set rates that we might otherwise be able to charge, could delay the use of rates that reflect increased costs and could subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

We are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, with respect to our natural gas lines and the Hazardous Liquids Pipeline Safety Act of 1979, as amended, with respect to our NGL lines, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, we are subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES”), and pursuant to which the DOT has implemented regulations establishing mandatory inspections for all United States oil (including NGL) and natural gas transportation pipelines and gathering lines meeting certain operational risk and location requirements. Moreover, the DOT has developed PIPES regulations that require operators of certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified unusually sensitive areas to comply with additional safety requirements addressing primarily corrosion and third-party damage concerns applicable to such pipelines.

Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with non-exempt pipelines. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, we may be affected by the testing, maintenance and repair of pipeline facilities downstream from our own facilities. Our NGL pipelines are also subject to integrity management and other safety regulations imposed by the TRRC.

Any regulatory expansion of the existing pipeline safety requirements or the adoption of new pipeline safety requirements could also increase our cost of operation and impair our ability to provide service during the period in which assessments and repairs take place, adversely affecting our business.

Because we handle natural gas, NGLs and other hydrocarbons 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 waste 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 wastes and other regulated 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 and, under certain circumstances, 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 substances or wastes into the environment.

There is inherent risk of environmental costs and liabilities in our business due to our handling of natural gas, NGLs and other hydrocarbons, 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, it is possible 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 to, or construction of, natural gas 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. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, we may not receive any material increase in operating cash flow from a project for some time. If we experience unanticipated or extended delays in generating operating cash flow from these projects, then we may need to reduce or reprioritize our capital budget in order to meet our capital requirements. We often rely on estimates of future production in deciding to construct additions to our gathering and transportation systems. These estimates may prove to be inaccurate because of the numerous technological, economic and other 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, and that in turn, could adversely affect our cash flows and results of operations.

If the cost of renewing existing rights-of-way increases, it may have an adverse impact on our profitability. In addition, if we are unable to obtain new rights-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 new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-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 new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing rights-of-way increases, then our results of operations could be adversely affected. In addition, increased rights-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, transportation and fractionation of natural gas and NGLs, including:

These risks could result in substantial losses due to personal injury and/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 leaks 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 and north Texas regions, in central and east Oklahoma and in Wyoming, and a natural disaster or other hazard affecting any of these areas could have a material adverse effect on our operations, even if our own facilities are not directly affected. For example, although we did not suffer significant damage due to Hurricane Ike in September 2008, the storm damaged gathering systems and processing and NGL fractionation facilities along the Gulf Coast, including facilities owned by third-party service providers on whom we depend in providing services to our customers. Some companies were required to curtail or suspend operations, which adversely affected various energy companies with assets in the region, including us.

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 generally 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 certain lost revenues arising from physical damage to our processing plants and certain pipeline facilities. 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 limited 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, fractionation and transportation business, 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, Oklahoma and Wyoming. Due to our limited 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 cash flows, results of operations and financial condition 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 2005, we began a process to annually document and evaluate our internal control over financial reporting to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act of 2002, which requires that the effectiveness of our internal control over financial reporting be subjected to annual assessment by management and annual audit by our independent registered public accounting firm. 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. 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 our compliance with policies or procedures deteriorates 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.

We own interests in limited liability companies and a general partnership in which third parties also own interests, which may limit our ability to influence significant business decisions affecting these entities.

In addition to our wholly owned subsidiaries, we own interests in a number of entities in which third parties also own an interest. These interests include our:

Although we serve as operator of Webb/Duval Gatherers, managing member and operator of Southern Dome, managing member and field operator of Bighorn and managing member of Fort Union, certain substantive business decisions with respect to these entities require the majority or unanimous approval of the owners or, in the case of Bighorn, of a management committee to which we have the right to appoint 50% of the members. Examples of some of these substantive business decisions include significant expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital and transactions not in the ordinary course of business, among others. Differences in views among the respective owners of these entities could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting their respective businesses and results of operations or prospects and, in turn, the amounts and timing of cash from operations distributed to their respective members or partners, including us.

In addition, we do not control the day-to-day operations of Fort Union. Our lack of control over Fort Union’s day-to-day operations and the associated costs of operations could result in our receiving lower cash distributions than we anticipate, which could reduce our cash flow available for distribution to our unitholders.

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 Law (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, except in limited circumstances. 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.

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

Our limited liability company agreement does not limit the number of additional limited liability company interests that we may issue at any time without the approval of our unitholders, including common units and other equity securities that rank senior to common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

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 agreements with our pre-IPO investors and investors in private placements we effected in 2005, 2006 and 2007, we have filed or agreed to file registration statements on Form S-3 registering sales by selling unitholders of an aggregate of 39,354,334 of our common units, including 3,245,817 common units to be issued upon conversion of our outstanding Class D units. If investors holding these units were to dispose of a substantial

portion of these units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. An increase in interest rates could also cause a corresponding decline in

demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Lower demand for our common units for any reason, including competition from other more attractive investment opportunities, would likely cause the trading price of our common units to decline. If we issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.

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 the other entities in which we own interests, and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, state and other laws and regulations or, in the case of other entities in which we own an interest, debt that they may incur, which could be governed by agreements restricting their ability to distribute cash to us. 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 our 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 would 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 indentures governing our outstanding senior notes and in our 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:

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 indebtedness.

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:

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:

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 of entity-level taxation, it would substantially reduce the amount of cash available for distribution to our unitholders.

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 with respect to this or any other tax matter.

Despite the fact that we are a limited liability company under Delaware law, it is possible in certain circumstances for a limited liability company such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we should be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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 would likely result in a substantial reduction in the value of our common units.

In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our federal gross income apportioned to Texas in the prior year. Imposition of such a tax on us by any other state will further reduce the cash available for distribution to our unitholders. Moreover, at the federal level, legislation has been considered that would have eliminated pass-through tax treatment for certain publicly traded limited liability companies. Although such legislation would not have applied to us as considered, it could be reintroduced in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Additionally, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely 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 affecting 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 the share of our income allocated to you even if you do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we allocate taxable income, 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, regardless of the amount of any 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 gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell, will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. 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), and non-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 to non-U.S. persons will be reduced by withholding taxes at the highest applicable tax rate, and non-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 a non-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 for certain 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.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units.

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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. 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, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. 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 also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

As a result of investing in our common units, you may be subject to state and local taxes and return filing requirements in states where you do not live.

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, Oklahoma, Wyoming, Colorado and Louisiana. Although Texas and Wyoming do not currently impose a

personal income tax, Oklahoma, Colorado and Louisiana do 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.

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:

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

For purposes of calculating the ratio of consolidated earnings to fixed charges:

Our common units represent limited liability company interests in us. The holders of our common 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, 2009, we had 54,601,458 common units outstanding. We also had 3,245,817 Class D units outstanding, all of which will convert into common units in February 2010, upon payment of our cash distribution for the fourth quarter of 2009.

Our limited liability company agreement governs the rights and obligations of our common unitholders. A copy of our limited liability company agreement is included in our other SEC filings and is incorporated by reference in this prospectus.

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

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.

In general, we may issue additional equity securities, and options, rights, warrants and appreciation rights relating to our equity securities, for any company purpose at any time and from time to time, to such persons for such consideration and on such terms and conditions as our Board of Directors shall determine, all without the approval of any unitholders. Each additional equity security authorized to be issued by us pursuant to our limited liability company agreement may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of our equity securities), as our Board of Directors shall determine, all without the approval of any unitholders.

We may choose to finance acquisitions by issuing additional common units or other equity securities. Holders of any additional common units we issue will be entitled to participate in our distributions of available cash. In addition, the issuance of additional common units or other equity securities may dilute the value of the existing common unitholders’ interests 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.

In general, common unitholders have the right to vote with respect to the election of our Board of Directors, 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.

If, at any time, any person owns more than 90% of the issued and outstanding membership interests of any class, such person will have the right, which it may transfer 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 Board of Directors, on at least 10 but not more than 60 days’ notice. Our unitholders are not entitled to dissenters’ rights of appraisal under our 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:

As a result of this limited call right, a holder of membership interests in our company may have its 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 its common units in the market. Please read “Material Tax Consequences—Disposition of Common Units.”

Our common units are listed on the Nasdaq Global Select Market under the symbol “CPNO.”

American Stock Transfer & Trust Company, LLC serves as registrar and transfer agent for our 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:

There will be no charge to unitholders 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 as transfer agent, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

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.

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:

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.

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 are limited to co-issuing debt securities and engaging in other activities incidental thereto. When used in this section “Description of Our 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 Energy” and “Copano Finance” refer strictly to Copano Energy, L.L.C. and Copano Energy Finance Corporation, respectively.

If we offer senior debt securities, we will issue them under a senior indenture. If we issue subordinated debt securities, we will issue them under a subordinated indenture. A form of each indenture is filed as an exhibit to the registration statement of which this prospectus is a part. We have not restated either indenture in its entirety in this description. You should read the relevant indenture because it, and not this description, controls your rights as holders of the debt securities. Capitalized terms used in this summary have the meanings specified in the indentures.

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:

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.

If specified in the prospectus supplement respecting a series of debt securities, the subsidiaries of Copano Energy specified in the prospectus supplement will fully and 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 stated 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 of Copano Energy’s wholly owned subsidiaries other than “minor” subsidiaries (except Copano Finance) as such term is interpreted in securities regulations 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.

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 obligations 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 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, except in the case of a lease of all or substantially all of the assets of an issuer, the issuer will be released from any further obligations under the indenture.

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.

We may supplement or amend an indenture if the holders of a majority in aggregate principal amount of the outstanding debt securities of each 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:

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

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:

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 insolvency event occurs with respect to either issuer, the entire principal of, premium, if any, and accrued interest on, all debt securities then outstanding will be due and payable immediately, without any declaration or other act on the part of the trustee or any holders. If any other 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 indemnity, 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.

Neither indenture will limit the amount of debt securities that we may issue, unless we indicate otherwise in a prospectus supplement. Each indenture will allow us to issue debt securities of any series up to the aggregate principal amount that we authorize.

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

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.

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 either 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.

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 indicated in the applicable prospectus supplement, 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.

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.

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.

The subordinated debt securities will rank junior in right of payment to all of our Senior Indebtedness. The definitions of “Senior Indebtedness” and “Designated Senior Indebtedness” will be set forth in the prospectus supplement respecting each series of subordinated debt securities. If the subordinated debt securities are guaranteed by any of the subsidiaries of Copano Energy, then the guarantees will be subordinated on like terms.

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

The subordinated indenture will not limit the amount of Senior Indebtedness that we or any guarantor may incur, unless otherwise indicated in the prospectus supplement.

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, except in the limited circumstances described below. Instead, one or more global debt securities will be issued to DTC, who 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

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 Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset servicing for U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post- trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. secu- rities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). The DTC Rules applicable to its participants are on file with the SEC.

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:

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:

(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 cash sufficient 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 with respect to the debt securities of that series; 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.

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

We will enter into the indentures with a trustee that is qualified to act under the Trust Indenture Act 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.

If the trustee has or acquires a conflicting interest within the meaning of the Trust Indenture Act, the trustee must 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.

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.

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.

Each indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of such indenture, every application by us for action by the trustee must 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.

General. We intend to pay quarterly distributions to our common unitholders of record on the applicable record date within 45 days after the end of each quarter (in February, May, August and November of each year) to the extent we have sufficient available cash, as defined in our limited liability company agreement. We will make distributions of available cash to common unitholders in accordance with their respective percentage interests.

Definition of Available Cash. Available cash generally means, with respect to any quarter:

Contractual Restrictions on Our Ability to Distribute Available Cash. If we are not in compliance with covenants contained in our revolving credit facility or the indentures governing our senior unsecured notes, 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.

If we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

For example, if a two-for-one split of the common units should occur, the quarterly distribution would be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional common 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 quarterly distribution level for each quarter by multiplying the 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.

If we dissolve in accordance with our 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 our 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 common unitholders to receive proceeds equal to their unrecovered capital plus the quarterly distribution for the quarter during which liquidation occurs. There may not be sufficient taxable gain upon our liquidation to enable common unitholders to fully recover all of these amounts.

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 of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated thereunder (the “Treasury 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”).

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 unitholder 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. The portion of our income that is qualifying income may change from time to time.

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, the Treasury 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 factual representations made by us, including:

(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.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

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 an association taxable 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.

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.

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.

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes except to the extent the amount of any such cash distribution exceeds 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 recapture and/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 (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

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.”

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 at-risk amount is subsequently increased, provided such losses do not exceed the unitholder’s tax basis in his units. 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.

In addition to the basis and at-risk limitations on the deductibility of losses, 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.

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:

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 or qualified dividend income. 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.

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.

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. 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 or certain other transactions, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder acquiring 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 such offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all holders of partnership interests immediately prior to such other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. 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.

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:

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.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and 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.”

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.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

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 all of our 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 subject to depreciation under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation 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 and any other Treasury Regulations. 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 property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property of which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets and Treasury Regulation 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 “—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 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.

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.”

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. We may not be entitled to any amortization deductions with respect to certain goodwill or properties 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.

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.

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 U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). 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 Treasury 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:

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.

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.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. 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.

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.

We will be considered to have been terminated for tax purposes if there are sales and exchanges that, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same unit are counted only once. 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. A constructive termination occurring on a date other than December 31 will result in our filing two tax returns (and unitholders receiving two Schedules K-1) for one fiscal year, and the cost of the preparation of these returns will be borne by all unitholders. 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. The IRS has announced recently that it plans to issue guidance regarding the treatment of constructive terminations of publicly traded partnerships such as us. Any such guidance may change the application of the rules discussed above and may affect the tax treatment of a unitholder.

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 Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation 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 property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the Treasury Regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets and Treasury Regulation Section 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 methods and lives 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.”

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. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our units.

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, cash distributions made to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form 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.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule 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 has made and 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.

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;

(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(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.

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:

(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 (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

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 for partnerships, individuals, S corporations and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive 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:

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, Oklahoma, Wyoming, Colorado and Louisiana. Although Texas and Wyoming do not currently impose a personal income tax, Oklahoma, Colorado and Louisiana do, 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 Collections.” 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.

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.

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.

The consolidated financial statements of Copano Energy, L.L.C. incorporated in this prospectus by reference from the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 and the effectiveness of Copano Energy, L.L.C.’s internal control over financial reporting have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference. Such financial statements 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 Bighorn Gas Gathering, L.L.C. as of December 31, 2007 and for the period from October 1, 2007 through December 31, 2007, incorporated in this prospectus by reference from Copano Energy, L.L.C.’s Annual Report on Form 10-K for the year ended December 31, 2008 have been audited by Deloitte & Touche LLP, independent auditors’, as stated in their report, which is incorporated herein by reference. Such financial statements have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.



Class of securities registered	Amount to be registered	Offering price per unit	Aggregate offering price	Amount of registration fee(1)
Common Units	5,750,000	$34.03	$195,672,500	$22,424.07


	Per Common Unit		Total
Price to the public	$	34.03	$	170,150,000

Underwriting discounts and commissions	$	1.32	$	6,600,000

Proceeds to Copano Energy, L.L.C. (before expenses)	$	32.71	$	163,550,000


Barclays Capital	BofA Merrill Lynch	J.P. Morgan
Morgan Stanley	Deutsche Bank Securities	Wells Fargo Securities


	Page
About this Prospectus Supplement and the Accompanying Prospectus		S-ii
Information Regarding Forward-Looking Statements		S-iii
Summary		S-1
Summary Historical Financial Information		S-9
Risk Factors		S-13
Use of Proceeds		S-14
Capitalization		S-15
Price Range of Common Units and Distributions		S-16
Material Tax Considerations		S-17
Underwriting (Conflicts of Interest)		S-19
Legal Matters		S-25
Experts		S-25
Where You Can Find More Information		S-26

PROSPECTUS DATED NOVEMBER 2, 2009

	Page
About This Prospectus		3
Where You Can Find More Information		3
Information Regarding Forward-Looking Statements		4
Copano Energy, L.L.C.		5
The Subsidiary Guarantors		5
Risk Factors		6
Use of Proceeds		28
Ratios of Earnings to Fixed Charges		28
Description of Our Common Units		28
Description of Our Debt Securities		31
Cash Distribution Policy		39
Material Tax Consequences		40
Legal Matters		55
Experts		55


	As of September 30, 2011
	Actual		As Adjusted
	(in thousands)
Cash and cash equivalents	$	53,534	$	53,534

Long-term debt:
Revolving credit facility(1)	$	295,000	$	132,031
Senior notes:
7.125% senior notes due 2021		360,000		360,000
7.75% senior notes due 2018		249,525		249,525

Total senior notes	$	609,525	$	609,525

Total long-term debt	$	904,525	$	741,556
Total members’ capital		906,228		1,069,197

Total capitalization	$	1,810,753	$	1,810,753


	Price Ranges				Cash Distributions per Unit
	Low		High		Cash Distributions per Unit
Fiscal Year 2012
March 31, 2012(1)	$	34.27	$	35.95			(2)

Fiscal Year 2011
December 31, 2011	$	26.08	$	34.28	$	.575
September 30, 2011		27.07		35.39		.575
June 30, 2011		31.17		37.40		.575
March 31, 2011		30.23		36.40		.575
Fiscal Year 2010
December 31, 2010	$	27.30	$	33.77	$	.575
September 30, 2010		24.49		29.43		.575
June 30, 2010		21.53		27.89		.575
March 31, 2010		20.70		25.62		.575


Underwriter	Number of Common Units
Barclays Capital Inc.		775,000
Merrill Lynch, Pierce, Fenner & Smith
Incorporated		775,000
J.P. Morgan Securities LLC		775,000
Morgan Stanley & Co. LLC		775,000
Deutsche Bank Securities Inc.		500,000
Wells Fargo Securities, LLC		500,000
Goldman, Sachs & Co.		350,000
RBC Capital Markets, LLC		350,000
Ladenburg Thalmann & Co. Inc.		100,000
Morgan Keegan & Company, Inc.		100,000

Total		5,000,000


	No Exercise		Full Exercise
Per unit	$	1.32	$	1.32
Total	$	6,600,000	$	7,590,000


Goldman, Sachs & Co.		RBC Capital Markets


Ladenburg Thalmann & Co. Inc.		Morgan Keegan