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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2010
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Transition Period From to

Commission file number: 001-32329

COPANO ENERGY, L.L.C.

(Exact name of registrant as specified in its charter)


Delaware (State of organization)		51-0411678 (I.R.S. Employer Identification No.)
2727 Allen Parkway, Suite 1200 Houston, Texas (Address of principal executive offices)		77019 (Zip Code)

(713) 621-9547

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:


Title of Each Class		Name of Exchange on which Registered
Common Units Representing Limited Liability Company Interests		The NASDAQ Global Select Market

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Title of Class

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of June 30, 2010, the aggregate market value of our voting and non-voting common equity held by non-affiliates of the registrant was approximately $1.7 billion based on $27.48 per common unit, the closing price of our common units as reported on The NASDAQ Global Select Market.

As of February 18, 2011, 66,002,430 of our common units were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:


Document		Parts Into Which Incorporated

Portions of the Proxy Statement for the Annual Meeting of Unitholders of Copano Energy, L.L.C. to be held May 18, 2011		Part III

PART I

Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C., its subsidiaries and entities it manages or operates.

As used generally in the energy industry and in this report, the following terms have the meanings indicated below. Please read the subsection of Item 1 captioned “— Industry Overview” for a discussion of the midstream natural gas industry.


/d:		Per day
$/gal:		U.S. dollars per gallon
Bbls:		Barrels
Bcf:		One billion cubic feet
Btu:		One British thermal unit
GPM:		Gallons per minute
Lean gas:		Natural gas that is low in NGL content
MMBtu:		One million British thermal units
Mcf:		One thousand cubic feet
MMcf:		One million cubic feet
NGLs:		Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
Residue gas:		The pipeline quality natural gas remaining after natural gas is processed
Rich gas		Natural gas that is high in NGL content
Tcf:		One trillion cubic feet
Throughput:		The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility


Item 1.	*Business*

The following discussion of our business segments provides information regarding our principal natural gas processing plants, pipelines and other assets. For a discussion of our results of operations, including pipeline throughput and processing rates, please read Item 7 of this report, captioned “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

General

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 Texas, Oklahoma, Wyoming and Louisiana and include approximately 6,424 miles of active natural gas gathering and transmission pipelines and eight natural gas processing plants, with over one Bcf/d of combined processing capacity. In addition to our natural gas pipelines, we operate 260 miles of natural gas liquids (“NGL”) pipelines, and through September 2009, we operated a 59-mile crude oil pipeline.

We were formed in August 2001 as a Delaware limited liability company to acquire entities operating under the Copano name since 1992. We completed our initial public offering (“IPO”) of common units representing limited liability company interests on November 15, 2004. Since our inception in 1992, we have grown through strategic and bolt-on acquisitions and organic growth projects. Our common units are listed on the NASDAQ Global Select Market under the symbol “CPNO.”

Recent Developments

DK pipeline expansion and new long-term agreements. On February 9, 2011, we announced plans to extend our recently completed 38-mile, 24-inch DK pipeline in DeWitt and Karnes Counties, Texas by adding 58 miles of 24-inch pipeline through Lavaca and Colorado Counties to directly connect the system into our Houston Central

complex. The pipeline extension will increase DK pipeline’s capacity from 225,000 MMBtu per day to 350,000 MMBtu per day and is expected to begin service in the fourth quarter of 2011. The DK pipeline expansion project is expected to cost approximately $100 million. We also announced that we have secured additional firm producer volume commitments for aggregate production of up to 120,000 MMBtu/d and additional commitments for production from approximately 135,000 gross acres in the Eagle Ford Shale.

Expanded commodity risk management portfolio. On February 2, 2011, we acquired puts for normal butane, isobutane, propane and West Texas Intermediate crude oil for 2012 and 2013 at strike prices reflecting current market conditions. The new hedges were executed with three investment grade counterparties for a net cost of approximately $5.5 million.

Expansion of NGL-handling capability. On January 18, 2011 we announced that we had entered into a long-term agreement for storage, fractionation and sale of mixed NGLs extracted at our Houston Central processing plant, and that we had formed Liberty Pipeline Group, LLC (a 50/50 joint venture with a subsidiary of Energy Transfer Partners) to construct, own and operate a 12-inch NGL pipeline (the “Liberty pipeline”). The Liberty pipeline will extend approximately 83 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 Hydrocarbons Company’s petrochemical facility in Calhoun County, Texas. The pipeline will have initial capacity of 75,000 barrels per day, 37,500 of which will be committed to us under a firm throughput agreement. Construction costs for the Liberty pipeline are expected to total approximately $52 million, of which we will contribute $26 million.

Our agreement with Formosa Hydrocarbons Company provides us with up to 37,500 Bbls/d of firm fractionation services beginning in the first quarter of 2013 for a term of 15 years. The agreement also provides that Formosa will purchase substantially all of the resulting NGL products and make product storage, barge dock loading and rail car loading available to us for operational reliability. Following the completion of Liberty Pipeline, which is expected by the summer of 2011, and until additional facility improvements at Formosa are complete, we will have access to a minimum of 5,000 barrels per day of existing Formosa fractionation capacity, as well as additional capacity on a “space available” basis.

Declaration of distribution. On January 12, 2011, our Board of Directors declared a cash distribution for the three months ended December 31, 2010 of $0.575 per common unit. The distribution, totaling $38.5 million, was paid on February 11, 2011 to all common unitholders of record at the close of business on February 1, 2011.

Expansion of Eagle Ford Gathering. On January 6, 2011, we announced plans to expand the scope of our Eagle Ford Gathering joint venture with Kinder Morgan through construction of additional pipeline facilities and a long-term agreement with Formosa for processing and fractionation services. In addition to 111 miles of pipeline currently under construction, which is on schedule to be completed in the third quarter of 2011, Eagle Ford Gathering will build a 54-mile, 24-inch crossover pipeline between existing Kinder Morgan pipelines, a 5,000 horsepower compressor station and an additional 20-mile, 20-inch diameter pipeline that will enable the joint venture to deliver gas to Formosa. Kinder Morgan will construct and operate the two additional pipelines, which are expected to be complete by the fourth quarter of 2011. Construction costs for the crossover pipeline are expected to total approximately $100 million, of which we will contribute $50 million.

Other approved capital projects for 2011. Our Board of Directors has approved approximately $242 million in expansion capital for projects for the full year of 2011 in addition to those described above. Our major areas of focus for 2011 include projects for Eagle Ford Shale development, including enhancements to our Houston Central complex, additional pipelines serving the north Barnett Shale Combo play, and additional pipeline, treating and processing capacity in Oklahoma.

Business Strategy

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


	•	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 are constructing new assets to capitalize on significant activity in the Eagle Ford Shale, near our Houston Central complex in Texas, and in the Woodford Shale, near our Mountains gathering systems in Oklahoma. Where our pipelines and processing plants 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.


	•	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 does not depend on commodity prices. For example, we have focused on replacing commodity-sensitive contracts with fixed-fee 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. Please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Contracts” and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

	•	Expanding through greenfield opportunities and strategic acquisitions. We pursue significant greenfield projects that leverage our strengths through alignment with producers. 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.

	•	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 will generate in comparison to our cost of capital under various commodity price scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.

	•	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, our focus turned to offering multiple natural gas and NGL market access to our customers. For example, multiple residue markets are available at the tailgate of our Houston Central complex, and we are working to secure alternatives for NGL handling through initiatives such as our 2010 startup and ongoing expansion of the Houston Central fractionator, our Liberty pipeline project and our execution of third-party fractionation or purchase arrangements for NGLs or purity products.

	•	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 raised $300 million in our private placement of preferred equity with TPG in anticipation of our need to finance capital projects to accommodate volume growth from shale plays in Texas and Oklahoma. We believe that the paid-in-kind distribution feature of the preferred units allows us the flexibility to maintain a strong balance sheet when


		organic growth projects are under construction, before they are generating cash flow that is accretive to our unitholders.


	•	Maintain 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 needed to win new business and to maintain valued long-term relationships.

Our Operations

Our Operating Segments

Overview

We manage and operate our business in three geographic segments: Texas, Oklahoma and Rocky Mountains. Our operating segments are summarized in the following table:

Copano Energy Operating Segments


						Year Ended
						December 31, 2010
		Pipeline Miles⁽¹⁾				Average
		/Number of		Throughput		Throughput/
		Processing		/Inlet		Inlet		Utilization
Segment	Assets	Plants		Capacity⁽²⁾⁽³⁾		Volumes⁽²⁾⁽³⁾		of Capacity

Texas	Natural Gas Pipelines⁽⁴⁾		2,005		1,139,900		349,922		31	%
	Processing Plants⁽⁵⁾		3		1,000,000		455,573		46	%
	NGL Pipelines⁽⁶⁾		260		93,630		19,109		20	%
Oklahoma	Natural Gas Pipelines		3,828		350,100		222,407		64	%
	Processing Plants⁽⁷⁾		5		168,000		108,506		65	%
Rocky Mountains	Natural Gas Pipelines⁽⁸⁾		591		1,550,000		948,133		61	%


(1)		Natural gas pipeline miles for Texas and Oklahoma exclude 588 miles and 2,973 miles, respectively, of inactive pipelines that are being held for potential future development.

(2)		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.

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

(4)		Includes the 153-mile Webb Duval system owned by Webb Duval Gatherers, an unconsolidated partnership in which we own a 62.5% interest.

(5)		Includes our processing plant in Lake Charles, Louisiana, which has limited operations.

(6)		Includes 98 miles of leased NGL pipelines.

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

(8)		Owned by Bighorn Gas Gathering, L.L.C. (“Bighorn”) and Fort Union Gas Gathering, L.L.C. (“Fort Union”), unconsolidated companies in which we own 51.0% and 37.04% interests, respectively. We do not operate Fort Union.

For additional disclosure about our segments, please read Note 14, “Segment Information,” to our consolidated financial statements included in Item 8 of this report.

The tables below provide summary descriptions of our Texas pipeline systems and processing plants.

Texas Pipelines


			Diameter of				Year Ended December 31, 2010
	Length		Pipe		Throughput		Average		Utilization
	(miles)		(range)		Capacity⁽¹⁾⁽²⁾		Throughput⁽¹⁾⁽²⁾		of Capacity

Natural Gas Pipelines:
South Texas⁽³⁾⁽⁴⁾		1,005		2²- 20²		652,800		168,639		26	%
Houston Central		332		2²- 12²		239,000		94,814		40	%
Upper Gulf Coast		238		2²- 12²		145,100		52,308		36	%
North Texas⁽⁵⁾		430		3²- 12²		103,000		34,161		33	%
NGL Pipelines:
Sheridan⁽⁶⁾		107		6²		30,900		4,241		14	%
Brenham		47		6²		20,250		—		—	%
Markham⁽⁷⁾		50		6²		17,980		7,958		44	%
KS⁽⁸⁾		51		6²		6,500		2,927		45	%
Saint Jo		5		6²		18,000		3,377		19	%


(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 are presented in Mcf/d. NGL pipeline throughputs are presented in Bbls/d.

(3)		Includes our Webb Duval system owned by Webb Duval Gatherers, an unconsolidated partnership in which we hold a 62.5% interest.

(4)		Throughput volumes presented in the table are net of intercompany transactions.

(5)		Excludes 588 miles of inactive pipelines held for potential future development.

(6)		We placed the western portion of the Sheridan NGL pipeline into purity propane service in April 2010.

(7)		We placed the Markham NGL pipeline into purity ethane service in May 2010.

(8)		We placed the KS NGL pipeline into purity propane service in April 2010.

Texas Processing


						Year Ended December 31, 2010
												Average
						Average			Utilization			Processing
		Throughput		Fractionation		Inlet			of			Volumes⁽¹⁾
Processing Plants	Facilities	Capacity⁽¹⁾		Capacity⁽¹⁾		Volumes⁽¹⁾			Capacity			NGLs			Residue

Houston Central	Cryogenic/lean oil		700,000		22,000		424,871			61	%		14,419	⁽²⁾		395,229
Saint Jo⁽³⁾	Cryogenic		100,000		—		29,630			51	%		3,688			23,491
Lake Charles	Cryogenic		200,000		—		1,072	⁽⁴⁾		1	%		34	⁽⁴⁾		1,044	⁽⁴⁾


(1)		Throughput capacity and inlet volumes are presented in Mcf/d. Fractionation capacity and NGL volumes are presented in Bbls/d. Residue volumes are presented in MMBtu/d.

(2)		NGL volumes from the Houston Central complex includes average daily volumes of 6,467 Bbls/d of ethane delivered to the Markham NGL pipeline after the pipeline was placed in service in May 2010, 3,885 Bbls/d of propane delivered to each of our Sheridan and KS NGL pipelines after these pipelines were placed in purity service in April 2010, 1,942 Bbls/d of isobutane and normal butane trucked from the Houston Central complex after the truck rack was placed in service in April 2010 and 2,028 Bbls/d of stabilized condensate delivered to the Enterprise Product Partners crude oil pipeline.

(3)		The Saint Jo plant was expanded from 50,000 Mcf/d to its designed operating capacity of 100,000 Mcf/d in November 2010.

(4)		Average inlet volumes and average processing volumes for the Lake Charles plant represent 3 days of activity in 2010. The Lake Charles plant operates only when the LNG regasification facility to which it is connected is operating and is sending natural gas to the plant.

As described above under “— Recent Developments,” we have undertaken various expansion capital projects in Texas to accommodate volume growth from the Eagle Ford Shale play. The table below provides summary descriptions of our major Texas capital projects.

Texas Expansion Projects


									Estimated
	Length		Diameter		Initial		Expanded		Costs		Expected In-
Project	(miles)		(range)		Capacity⁽¹⁾		Capacity⁽¹⁾		($ in millions)⁽⁴⁾		Service Date

Houston Central fractionation expansion		—		—		22,000		44,000	$	66	Fourth Quarter 2011
DK Pipeline extension		58		24²		195,000		303,000	$	100	Fourth Quarter 2011
Eagle Ford Gathering⁽²⁾
Initial pipeline		111		24²- 30²		325,000		—	$	175	Third Quarter 2011
Crossover pipeline		74		20²- 24²		176,000		—	$	100	Fourth Quarter 2011
Liberty pipeline⁽³⁾		83		12²		75,000		—	$	52	Third Quarter 2011


(1)		Throughput capacity is presented in Mcf/d. Fractionation capacity is presented in Bbls/d.

(2)		Constructed through Eagle Ford Gathering, a joint venture in which we own a 50% interest.

(3)		Constructed through Liberty Pipeline Group, a joint venture in which we own a 50% interest.

(4)		Joint venture project costs presented are gross amounts; our share of such costs is 50%.

South Texas Systems

We deliver a substantial majority of the natural gas gathered on our systems in south Texas to our Houston Central complex for treating, processing or conditioning and fractionation, as needed. Our gathering systems in this area deliver to our Houston Central complex via the Laredo-to-Katy pipeline, a 30-inch diameter natural gas transmission pipeline system owned by a subsidiary of Kinder Morgan, which extends along the Texas Gulf Coast from south Texas to Houston.

Our south Texas gathering systems that deliver to our Houston Central complex gather natural gas from fields located in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Wells, Karnes, Live Oak, Nueces, Refugio, San Patricio and Webb Counties. Some of these systems also deliver to Natural Gas Pipeline Company of America, DCP Midstream, Houston Pipe Line (an affiliate of Energy Transfer Partners), Southcross Energy, Texas Eastern Transmission, CenterPoint Energy, ExxonMobil and Enterprise Product Partners.

Our south Texas systems include the Webb Duval gathering system, which is owned by Webb Duval Gatherers, a general partnership that we operate and in which we own a 62.5% interest. We operate the Webb Duval system subject to the rights of the other partners, including rights to approve capital expenditures in excess of $100,000, financing arrangements by the partnership or any expansion projects associated with this system. In addition, each partner has the right to use its pro rata share of pipeline capacity on this system, subject to applicable ratable take and common purchaser statutes.

Our DK pipeline provides rich gas gathering services for Eagle Ford Shale producers in DeWitt and Karnes Counties, Texas and upon completion of the DK pipeline extension, in Lavaca and Colorado Counties, Texas. We transport natural gas gathered on the DK pipeline to our Houston Central complex for processing via Kinder Morgan’s Laredo-to-Katy pipeline. We have begun work on a 58-mile extension of the DK pipeline to connect it directly to our Houston Central complex.

Our Copano Bay gathering system and Encinal Channel pipeline operate onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. These systems gather natural gas offshore in Aransas, Nueces and Copano Bays and from nearby onshore lands. Natural gas, produced water and condensate are separated at our Lamar and Estes Cove separation and dehydration facilities. We deliver any natural gas from the Estes Cove facility to the Lamar facility, which delivers gas to a third party for processing.

Our Houston Central gathering systems gather natural gas in Colorado, DeWitt, Lavaca, Victoria and Wharton Counties, and deliver the gas to our Houston Central complex directly, instead of via Kinder Morgan’s

Laredo-to-Katy pipeline. These systems can also take delivery of natural gas from Enterprise Products Partners and DCP Midstream.

Our Houston Central complex has approximately 700,000 Mcf/d of processing capacity and includes:


	•	8,029 horsepower of inlet compression;

	•	8,400 horsepower of tailgate compression;

	•	a 1,200 GPM amine treating system for removal of carbon dioxide and low-level hydrogen sulfide;

	•	two 250,000 Mcf/d refrigerated lean oil trains;

	•	one 200,000 Mcf/d cryogenic turbo-expander train;

	•	a 22,000 Bbls/d NGL fractionation facility (expanding to 44,000 Bbls/d);

	•	a truck rack with the capacity to facilitate the transport of 11,000 Bbls/d of NGLs; and

	•	882,000 gallons of storage capacity for propane, butane-natural gasoline mix and stabilized condensate.

The Houston Central complex is also capable of conditioning natural gas, which means to process gas only to the extent required to meet downstream pipeline hydrocarbon dew point specifications. Conditioning capability allows us to preserve a greater portion of the value of natural gas when processing is not economic because it allows us to minimize the level of NGLs we remove from the natural gas stream.

Most of the natural gas we receive at Houston Central is delivered by the Kinder Morgan Laredo-to-Katy pipeline, which the plant straddles. In addition, our Houston Central gathering systems deliver gas to the complex. The plant has tailgate interconnects with Kinder Morgan, Houston Pipe Line, Tennessee Gas Pipeline Company and Texas Eastern Transmission for redelivery of residue natural gas. In addition, we operate four NGL pipelines at the tailgate of the plant. Enterprise Product Partners operates a crude oil and stabilized condensate pipeline that runs from the tailgate of the plant to refineries in the greater Houston area.

The plant and related facilities are located on a 163-acre tract of land, which we lease under three long-term lease agreements.

Sheridan, KS NGL, Brenham and Markham Pipelines. The western portion of the Sheridan NGL pipeline originates at the tailgate of the Houston Central complex. We are using it to deliver purity propane to Dow through an interconnection with the KS NGL pipeline as noted below. The Sheridan NGL pipeline can also be used for delivery of NGLs into Enterprise Products Partners’ Seminole Pipeline on the west side of Houston. The eastern portion of the Sheridan NGL pipeline originates at the Enterprise Products Partners’ Almeda station in south Houston and delivers butylenes to the Shell Deer Park plant on the Houston Ship Channel.

We leased the KS NGL pipeline from Dow Hydrocarbon and Resources in January 2010 and are using it to interconnect with the Sheridan NGL pipeline for deliveries of purity propane to Dow Hydrocarbon. Our lease agreement for the KS NGL pipeline expires in January 2015.

The Brenham NGL pipeline originates at the tailgate of our Houston Central complex and provides us the option of delivering NGLs into Enterprise Products Partners’ Seminole pipeline near Brenham, Texas. We lease the Brenham NGL pipeline from Kinder Morgan under a lease agreement that expires December 31, 2024.

We placed the Markham NGL pipeline into service for delivery of mixed NGLs to DCP Midstream beginning in August 2009. After we expanded the deethanizer at our Houston Central complex, we converted this pipeline into a purity ethane pipeline and placed it into purity ethane service in May 2010.

Our Commercial Relationship with Kinder Morgan. Kinder Morgan owns a 2,500-mile natural gas pipeline system that extends along the Texas Gulf Coast from south Texas to Houston and primarily serves utility and industrial customers in the Houston, Beaumont and Port Arthur areas. Kinder Morgan sells and transports natural gas, and we use Kinder Morgan as a transporter because our Houston Central complex straddles its 30-inch-diameter Laredo-to-Katy pipeline. Using Kinder Morgan as a transporter allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central complex and downstream

markets. Kinder Morgan’s pipeline also delivers to our Houston Central complex natural gas for its own account, which we refer to as “KMTP Gas.” Under our contractual arrangements relating to KMTP Gas, we receive natural gas at our plant, process or condition it and sell the NGLs to third parties at market prices. For a discussion of our agreements with Kinder Morgan, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Contracts.”

In 2010, we and Kinder Morgan formed Eagle Ford Gathering, a joint venture to provide midstream natural gas services to Eagle Ford Shale producers. Eagle Ford Gathering is constructing a 111-mile, 30-inch and 24-inch natural gas pipeline from the western Eagle Ford Shale play to Kinder Morgan’s Freer compressor station in Duval County, Texas, which we expect to begin full service in the third quarter of 2011. Initially, Kinder Morgan committed to Eagle Ford Gathering 375,000 MMBtu/d of transportation capacity on its Laredo-to-Katy pipeline, and we committed 375,000 MMBtu/d of processing capacity at our Houston Central complex. Eagle Ford Gathering fully subscribed this initial 375,000 MMBtu/d of transportation and processing capacity in November 2010, and in January 2011, we announced that Eagle Ford Gathering would expand its ability to provide services to producers through an additional 74 miles of pipeline that link existing Kinder Morgan pipelines and provide access to processing capacity under a new contract with Formosa Hydrocarbons. The crossover facilities will bring the total capacity of Eagle Ford Gathering to 600,000 MMBtu/d and are expected to be placed into service by the end of 2011.

Upper Gulf Coast Systems

Our Upper Gulf Coast systems are used for gathering, transportation and sales of natural gas to the north of Houston, Texas, in Houston, Walker, Grimes, Montgomery and Harris Counties. In addition to gas we gather, we receive natural gas from interconnects with Houston Pipe Line, Kinder Morgan, Tennessee Gas Pipeline’s north zone delivery meter, Atmos Pipeline — Texas, Enbridge Pipelines (East Texas) and Texas Eastern Transmission. We deliver the natural gas gathered or transported on these systems to multiple CenterPoint Energy city gates in Montgomery and Walker Counties, to Universal Natural Gas and Entergy’s Lewis Creek generating plant, and to several industrial consumers.

North Texas Systems

Our pipelines in north Texas gather natural gas from the north Barnett Shale Combo play in Cooke, Denton, Grayson, Montague and Wise Counties. We deliver natural gas gathered in north Texas to our Saint Jo processing plant in Montague County, Texas, and to third-party processing plants and pipelines. Our systems in north Texas have interconnects with Targa Resources, Atlas Pipeline, SemGas, Atmos and Natural Gas Pipeline of America. We constructed our Saint Jo plant, a cryogenic turbo expander processing plant, to address anticipated drilling activity and provide additional delivery points to producers in north Texas, and placed it in service in September 2009. The Saint Jo plant was expanded from a capacity of 50,000 Mcf/d to its designed capacity of 100,000 Mcf/d in November 2010. The Saint Jo plant includes a 1,200 GPM amine treating facility and condensate stabilization facilities and also has conditioning capability. Our Saint Jo NGL pipeline transports NGLs from the plant to ONEOK Hydrocarbon’s Arbuckle NGL pipeline.

Oklahoma

Our Oklahoma segment operates in active natural gas producing areas in central and east Oklahoma and includes assets we acquired through our purchases of Cimmarron Gathering, LP in May 2007 and ScissorTail Energy, LLC in August 2005. These assets include nine primarily low-pressure gathering systems occupying approximately 53,000 square miles and five processing plants, one of which we own through our majority interest in Southern Dome.

The tables below provide summary descriptions of our Oklahoma pipeline systems and processing plants.

Oklahoma Pipelines


							Year Ended
			Diameter of				December 31, 2010
	Length		Pipe		Throughput		Average		Utilization
	(miles)		(range)		Capacity⁽¹⁾⁽²⁾		Throughput⁽¹⁾⁽²⁾		of Capacity

Natural Gas Pipelines
Stroud		902		2²- 16²		121,000		101,529		84	%
Milfay		366		2²-16²		15,000		10,370		69	%
Glenpool		1,019		2²- 10²		20,000		8,654		43	%
Twin Rivers		558		2²- 12²		23,000		13,031		57	%
Central Oklahoma⁽³⁾		225		2²- 10²		4,100		3,745		91	%
Osage		563		2²- 8²		32,000		19,895		62	%
Mountain⁽⁴⁾		195		2²- 20²		135,000		65,183		48	%


(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 are presented in Mcf/d.

(3)		Excludes 2,973 miles of inactive pipelines held for potential future development.

(4)		The Mountain system consists of three separate systems: Blue Mountain, Cyclone Mountain and Pine Mountain.

Oklahoma Processing


				Year Ended December 31, 2010
				Average		Utilization			Average Processing
		Throughput		Inlet		of			Volumes⁽¹⁾
Processing Plants	Facilities	Capacity⁽¹⁾		Volumes⁽¹⁾		Capacity			NGLs		Residue

Paden	Cryogenic refrigeration Nitrogen rejection⁽³⁾		100,000		76,727		77	%		11,773		60,498
Milfay	Propane refrigeration		15,000		9,438		63	%		789		8,250
Glenpool	Cryogenic		25,000		8,116		32	%		402		11,066
Burbank	Propane refrigeration		10,000		3,450		34	%		217		2,856
Southern Dome⁽²⁾	Propane refrigeration		18,000		10,775		60	%		472		10,452


(1)		Throughput capacity and inlet volumes are presented in Mcf/d. NGL volumes are presented in Bbls/d. Residue volumes are presented in MMBtu/d.

(2)		We own a majority interest in Southern Dome, which owns the Southern Dome plant. The plant is designed for operating capacity of 30,000 Mcf/d. Throughput currently is limited to 18,000 Mcf/d due to inlet compression.

(3)		The nitrogen rejection unit removes entrained nitrogen from the natural gas stream associated with the cryogenic portion of the Paden plant, which has capacity of 60,000 Mcf/d.

In addition to transporting natural gas to our plants, our Oklahoma segment delivers natural gas to five third-party plants for processing. Depending on our contractual arrangements, third-party processors collect processing fees, retain a portion of the NGLs or residue gas or retain a portion of the proceeds from the sale of the NGLs and residue gas in exchange for their services. Average daily volumes processed at third-party plants for our Oklahoma segment were 40,936 Mcf/d for the year ended December 31, 2010.

Stroud System and Interconnected Area

The Stroud system is located in Lincoln, Oklahoma, Pottawatomie, Seminole and Okfuskee Counties, Oklahoma. In 2010, we delivered approximately 81% of the average throughput on this system to our Paden plant, and we delivered the remainder to third-party processing plants.

The Paden plant has a 60,000 Mcf/d turbo-expander cryogenic facility placed in service in June 2001, and a 40,000 Mcf/d refrigeration unit that was added in May 2007. The Paden plant also has the ability to reduce (by approximately 22%) the ethane extracted from natural gas processed, or “ethane rejection” capability. This capability provides us an advantage when market prices or operating conditions make it more desirable to retain ethane within the gas stream. Field compression provides the necessary pressure at the plant inlet, eliminating the need for inlet compression. The plant also has inlet condensate facilities, including vapor recovery and condensate stabilization.

Wellhead production around the Paden plant includes natural gas high in nitrogen, which is inert and reduces the Btu value of residue gas. In 2008, we added a nitrogen rejection unit to the Paden plant, which allows us to process high-nitrogen natural gas while remaining in compliance with downstream pipeline gas quality specifications. The nitrogen rejection unit removes excess nitrogen from residue gas at the tailgate of the plant’s cryogenic facility.

We deliver residue gas from the Paden plant to either Enogex (a subsidiary of OGE Energy Corp.) or ONEOK Gas Transmission. We deliver NGLs from the Paden plant to ONEOK Hydrocarbon and condensate is trucked by Enterprise Product Partners.

Milfay System and Processing Plant. The Milfay system is located in Tulsa, Creek, Payne, Lincoln and Okfuskee Counties, Oklahoma. We deliver natural gas gathered on the Milfay system to our Milfay plant, and have the ability to deliver to the Paden plant as well. We deliver the residue gas from the Milfay plant into ONEOK Gas Transmission and the NGLs to ONEOK Hydrocarbon.

Glenpool System and Processing Plant. The Glenpool system is located in Tulsa, Wagoner, Muskogee, McIntosh, Okfuskee, Okmulgee and Creek Counties, Oklahoma. Substantially all of the natural gas from the Glenpool system is delivered to our Glenpool plant. We deliver the residue gas from the Glenpool plant into either ONEOK Gas Transmission or the American Electric Power Riverside power plant, and the NGLs to ONEOK Hydrocarbon.

Twin Rivers System. The Twin Rivers system is located in Okfuskee, Seminole, Hughes, Pontotoc and Coal Counties, Oklahoma. We deliver substantially all of the Twin Rivers system’s volumes to a third-party plant for processing.

Central Oklahoma System. The Central Oklahoma system consists of five gathering systems located in Garvin, Stephens, McClain, Oklahoma and Carter Counties, Oklahoma. We deliver gas gathered on the Central Oklahoma system to two third-party plants for processing.

Osage System. The Osage system is located in Osage, Pawnee, Payne, Washington and Tulsa Counties, Oklahoma. Wellhead production on the eastern portion of the Osage system tends to be lean and is not processed. This gas makes up the majority of the system throughput and is delivered to Enogex and ONEOK Gas Transmission. Wellhead production on the western portion of the Osage system tends to be richer; we currently deliver the production to Keystone Gas, which delivers it to a third-party processor. We began directing rich gas from the Osage system to our new Burbank plant in the second quarter of 2010.

Burbank Processing Plant. The Burbank plant, located in Osage County, is a 10,000 Mcf/d propane refrigeration facility which was placed in service in the second quarter of 2010. We deliver the residue gas from the Burbank plant into PostRock KPC Pipeline and sell the NGLs to Murphy Energy via trucks.

Mountain Systems. The Mountain systems are located in Atoka, Pittsburg and Latimer Counties, in the Arkoma Basin, and include the Blue Mountain, Cyclone Mountain and Pine Mountain systems. Wellhead production on the Mountain systems is lean and generally does not require processing. We deliver natural gas from the Mountain systems to, among others, CenterPoint and Enogex.

Crude Oil Pipeline. We sold our only crude oil pipeline in a transaction that was effective October 1, 2009.

Southern Dome. We own a majority interest in Southern Dome, which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County. We are the managing member of Southern Dome and serve as its operator. Southern Dome also operates a 3.4-mile gathering system

owned by a single producer. Under a gas purchase and processing agreement between Southern Dome and this producer, substantially all of the natural gas from the gathering system is delivered to the Southern Dome processing plant, and the remainder is delivered to a third party for processing. Southern Dome receives a fee for operating the gathering system and retains a percentage of the producer’s residue gas and NGLs at the tailgate of the Southern Dome plant. We deliver the residue gas to ONEOK Gas Transmission and sell the NGLs to Murphy Energy via trucks.

We are obligated to make 73% of capital contributions requested by Southern Dome up to a maximum commitment amount of $18.25 million. We are entitled to receive 69.5% of member distributions until “payout,” which refers to a point at which we have received distributions equal to our capital contributions plus an 11% return. After payout occurs, we will be entitled to 50.1% of member distributions. As of December 31, 2010, we have made $12.4 million in aggregate capital contributions to Southern Dome and have received an aggregate of $11.4 million in member distributions.

Rocky Mountains

Our Rocky Mountains segment operates in coal-bed methane producing areas in Wyoming’s Powder River Basin. We acquired the business and assets in this segment through our purchase of Denver-based Cantera in October 2007. Our Rocky Mountains assets consist primarily of a 51.0% managing membership interest in Bighorn, a 37.04% managing membership interest in Fort Union, two firm gathering agreements with Fort Union and two firm capacity transportation agreements with Wyoming Interstate Gas Company (“WIC”). Two subsidiaries of ONEOK Partners own the remaining 49% membership interests in Bighorn, and subsidiaries of Anadarko, Williams, and ONEOK Partners own the remaining 62.96% membership interests in Fort Union. Bighorn and Fort Union operate natural gas gathering systems in the Powder River Basin.

Rocky Mountains Pipelines and Services⁽¹⁾


			Diameter of				Year Ended December 31, 2010
	Length		Pipe		Throughput		Average		Utilization
	(miles)		(range)		Capacity⁽²⁾		Throughput⁽³⁾		of Capacity

Natural Gas Pipelines⁽¹⁾		591		6²- 24²		1,550,000		948,133		61	%
Producer Services⁽⁴⁾		—		—		—		113,755		—


(1)		Consists of pipelines owned by Bighorn and Fort Union. Fort Union also has 1,500 GPM of amine treating capacity.

(2)		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.

(3)		Natural gas pipeline throughputs are presented in Mcf/d.

(4)		Producer services volumes consist of volumes we purchased for resale, volumes gathered under our firm capacity gathering agreements with Fort Union and volumes transported using our firm capacity agreements with WIC.

Bighorn Gathering System

The Bighorn gas gathering system is located in Johnson, Sheridan and Campbell Counties, Wyoming. Bighorn provides low and high pressure natural gas gathering service to coal-bed methane producers in the Powder River Basin. Due to the lean nature of coal-bed methane wellhead production, gas gathered on the Bighorn system does not require processing and is delivered directly into the Fort Union gas gathering system at the southern terminus of the Bighorn system.

Although we serve as manager and field operator of Bighorn, certain significant business decisions with respect to Bighorn require the majority or unanimous approval of a management committee to which we have the right to appoint 50% of the committee members. Examples include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, the determination of excess cash for mandatory distribution to members, dispositions of assets or entry into new gathering agreements or amendments to existing gathering agreements, among others.

Fort Union Gathering System

The Fort Union gas gathering system is located in Campbell and Converse Counties, Wyoming. Fort Union takes high-pressure delivery of gas from the Bighorn system and also provides high pressure gas gathering services to producers that deliver gas directly or indirectly into the Fort Union system. Natural gas gathered from these producers is relatively high in carbon dioxide and, accordingly, must be treated at Fort Union’s Medicine Bow amine treating facility in order to meet the quality specifications of downstream pipelines. Pipeline interconnects downstream from the Fort Union system include WIC, Kinder Morgan Interstate Gas Transportation Company and Colorado Interstate Gas Company.

Fort Union gathers a majority of the gas across its system under standard firm gathering agreements between Fort Union and each of its four owners, including us. Pursuant to these agreements, each of Fort Union’s owners is obligated to pay for a fixed quantity of firm gathering capacity (referred to as demand capacity) on the system, regardless of whether the owner uses the capacity. Also, each owner has the right to use a fixed quantity of firm gathering capacity on the system (referred to as variable capacity) that must be paid for only if used. To the extent an owner does not use its allocated capacity or market it to third parties, the capacity is available for use by the other owners. Any capacity not used by the owners or marketed to third parties becomes available to third parties under interruptible gathering agreements.

The demand capacity arrangement is intended to ensure that Fort Union recovers its costs for capital projects plus a minimum rate of return on its capital invested. As a project’s costs are recovered, the owners’ respective demand capacity related to that project converts to variable capacity. Currently, 48% of Fort Union’s total firm capacity is demand capacity, which expires in 2017. The variable capacity gathering agreements between Fort Union and its owners terminate only upon mutual agreement of the parties.

Although we serve as the managing member of Fort Union, we do not operate the Fort Union system, nor do we provide certain administrative services. Western Gas Wyoming, L.L.C., a subsidiary of Anadarko, acts as field operator and conducts all construction and field operations, while the ONEOK Partners subsidiary acts as administrative manager and provides gas control, contracts management and contract invoicing services. As managing member of Fort Union, we perform all other acts incidental to the management of Fort Union’s business, including determining distributions to owners, executing gathering agreements, approving certain capital expenditures and monitoring the performance of the field operator and administrative manager, subject to the requirement that certain significant business decisions receive the 65% or unanimous approval of the owners. Examples include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, among others.

Producer Services

We provide services to a number of producers in the Powder River Basin, including producers who deliver gas into the Bighorn or Fort Union gathering systems, using our firm capacity on Fort Union and WIC to provide producers access to downstream interstate markets.

Our gathering agreements with Fort Union (which expire only upon mutual agreement of the parties) currently provide us with total capacity of 381,398 Mcf/d consisting of demand capacity of 100,000 Mcf/d and variable capacity of up to 281,398 Mcf/d. Under these agreements, Fort Union gathers gas from producers and from Bighorn and delivers it to WIC near Glenrock, Wyoming. Our transportation agreements with WIC provide us with 216,100 MMBtu/d of firm capacity on WIC’s Medicine Bow lateral pipeline. WIC transports natural gas from the terminus of the Fort Union system, as well as other receipt points, to the Cheyenne Hub, which provides a connection to five major interstate pipelines.

Our long-term WIC agreements extend through 2019, with a right to renew for additional five-year terms. Through the capacity release program established under WIC’s FERC gas tariff, we have released our WIC capacity to producers in the Powder River Basin. The producers, in turn, have agreed to pay WIC for the right to use our WIC capacity. Our WIC capacity release covers all of our long-term WIC capacity and continues through 2019. We are obligated to pay for our capacity on WIC’s Medicine Bow lateral regardless of whether we use the capacity. Notwithstanding our capacity release, we remain obligated to pay WIC for such capacity in the event and to the extent that a replacement shipper to whom such capacity has been released fails to pay.

Natural Gas Supply

We continually seek new supplies of natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage or by obtaining natural gas supplies that were previously gathered on third-party gathering systems. We contract for supplies of natural gas from producers under a variety of contractual arrangements. The primary term of each contract varies significantly, ranging from one month to the life of the dedicated reserves or producers may commit all volumes from dedicated reserves or a specific volume amount for an agreed upon term. The terms of our natural gas supply contracts vary depending on, among other things, gas quality, NGL content, pressure of natural gas produced relative to downstream pressure requirements, competitive environment at the time the contract is executed and customer requirements. For a summary of our most common contractual arrangements, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Contracts.”

We generally do not obtain reservoir engineering reports evaluating reserves dedicated to our pipeline systems due to the cost of such evaluations and the lack of publicly available producer reserve information. Accordingly, we do not have estimates of total reserves dedicated to our assets, the average production decline of producer wells or the anticipated life of producing reserves, and volumes of natural gas transported on our pipeline systems in the future could be less than we anticipate. This may cause our revenues and operating income to be less than we expect. See “Risk Factors — Risks Related to Our Business.”

Each of our operating segments is affected by the level of drilling in its operating area. During 2010, we saw increases in natural gas and NGL prices and expanding of the capital and credit markets as compared to the levels experienced during the economic uncertainty of 2009. During 2010, we saw a considerable increase in the activity level of the domestic shale plays, and particularly in the Eagle Ford Shale, north Barnett Shale Combo and the Woodford Shale. Although commodity prices and financial market conditions have continued to recover, improvements in drilling activity remain relatively low in our conventional drilling areas, and as producers focus on the unconventional shale plays, it remains unclear when producers will undertake sustained increases in drilling activity throughout the conventional areas in which we operate. In the Powder River Basin, producers must “dewater” newly drilled coal-bed methane wells to draw the methane gas to the surface, which introduces a delay of twelve to eighteen months into the process of connecting newly drilled natural gas supplies. Both the effects of declining drilling activity on our Rocky Mountains systems due to the commodity price environment and the recovery in volumes after producers resume drilling will be delayed because of dewatering. Dewatering is also required in the Hunton formation in Oklahoma, although the process used in that region generally requires less time to complete.

For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Trends and Uncertainties — Commodity Prices and Producer Activity.”

Texas

During the year ended December 31, 2010, our Texas segment’s top suppliers by volume of natural gas were Upstream Energy, EOG Resources, Rosetta Resources, Newfield Exploration and XTO Energy, which collectively accounted for approximately 22% of the natural gas delivered to our Texas systems during the period.

Oklahoma

Pursuant to a contract that extends through mid-year 2020, our largest Oklahoma producer by volume has dedicated to us all of its production within a 1.1 million acre area. We also have dedications from other producers covering their production within an aggregate 572,800 acres pursuant to contracts ending between 2014 and 2016.

During the year ended December 31, 2010, our Oklahoma segment’s top producers by volume of natural gas were New Dominion, Equal Energy, Eagle Energy Production, Northeast Shelf Energy and Alta Natural Resources, which collectively accounted for approximately 66% of the natural gas delivered to our Oklahoma systems during the period.

Rocky Mountains

Under Fort Union’s operating agreement, the owners of Fort Union established an area of mutual interest (“AMI”) covering approximately 2.98 million acres in Converse, Campbell and Johnson Counties, Wyoming. Under the AMI, the owners have committed all gas production from the AMI to the Fort Union system up to the total capacity of the Fort Union system based on each owner’s total firm capacity rights.

During the year ended December 31, 2010, Fort Union’s top three shippers based on gathering fees accounted for approximately 85% of Fort Union’s revenue.

The owners of Bighorn have established an approximately 3.8 million-acre AMI within the Powder River Basin of northern Wyoming and southern Montana, which provides that projects undertaken by the owners or their subsidiaries in the AMI must be conducted through Bighorn. Additionally, production from leases covering more than one million acres of land within the Powder River Basin has been dedicated to the Bighorn Gathering system by producers. Bighorn’s largest Rocky Mountains producer by volume has dedicated to Bighorn approximately 250,000 acres pursuant to a contract that extends through 2019. Bighorn also has dedications from other producers within the same dedicated area pursuant to contracts ending primarily between 2011 and 2019.

During the year ended December 31, 2010, Bighorn’s top two producers based on gathering fees collectively accounted for approximately 84% Bighorn’s revenue.

Competition

The midstream natural gas industry is highly competitive. Competition is based primarily on the reputation, efficiency, flexibility, size, credit quality and reliability of the gatherer, the pricing arrangements offered by the gatherer, location of the gatherer’s pipeline facilities and the gatherer’s ability to offer a full range of services, including natural gas gathering, transportation, compression, dehydration, treating, processing, NGL transportation and fractionation. We believe that offering an integrated package of services allows us to compete more effectively for new natural gas supplies in our operating regions.

We face strong competition in acquiring new natural gas supplies and in pursuing acquisition opportunities as part of our long-term growth strategy. Our competitors include major interstate and intrastate pipelines, other natural gas gatherers and natural gas producers that gather, process and market natural gas. Our competitors may have capital resources and control supplies of natural gas greater than ours.

Texas

We provide comprehensive services to natural gas producers in our Texas segment, including gathering, transportation, compression, dehydration, treating, conditioning and processing and NGL transportation, fractionation and marketing. We believe our ability to furnish this full slate of services gives us an advantage in competing effectively for new supplies of natural gas because we can provide the services that producers,

marketers and others require to connect their natural gas quickly and efficiently. In addition, using centralized treating and processing facilities, we can in most cases attach producers that require these services more quickly and at a lower initial capital cost than our competitors, due in part to the elimination of some field equipment and greater economies of scale at our Houston Central complex. For natural gas that exceeds the maximum carbon dioxide and NGL specifications for interconnecting pipelines and downstream markets, we believe that we offer treating, conditioning and other processing and fractionation services on competitive terms.

Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, Lobo Pipeline Company (an affiliate of ConocoPhillips), Kinder Morgan, DCP Midstream, Southcross Energy, Energy Transfer Partners, Targa Resources, Atlas Pipeline, Devon Energy and Regency.

Oklahoma

We provide comprehensive services to natural gas producers in our Oklahoma segment, including gathering, transportation, compression, dehydration, treating and processing and, at our Paden plant, nitrogen rejection. We believe our ability to furnish this full slate of services gives us an advantage in competing effectively for new supplies of natural gas because we can provide the services that producers, marketers and others require to connect their natural gas quickly and efficiently.

Most of our Oklahoma systems offer low-pressure gathering service, which is attractive to producers. We have made significant investments in limited-emissions, multi-stage compressors for our Oklahoma compression facilities, which has allowed for quicker permitting and installation, thereby allowing us to provide the low pressure required by producers more efficiently. We believe this approach provides us a competitive advantage.

Our major competitors for natural gas supplies and markets in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, Atlas Pipeline, ONEOK Field Services, Hiland Partners, Enogex, MarkWest and Enerfin.

Rocky Mountains

A significant portion of the gas on the Bighorn and Fort Union systems is dedicated under long-term gas gathering agreements.

Our major competitors for natural gas gathering supplies and markets in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy, Western Gas Resources and our major competitor in providing take away capacity from the Rocky Mountains segment is the Bison Interstate Pipeline, which began service in January 2011.

Industry Overview

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets and consists of natural gas gathering, compression, dehydration, treating, conditioning, processing, transportation and fractionation, see diagram of the industry below.

Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small-diameter pipelines that collect natural gas from points near producing wells and deliver it to larger pipelines for further transmission.

Compression. Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Because wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it will be unable to overcome the higher gathering system pressure. In contrast, if field compression is installed, a declining well can continue delivering natural gas.

Natural gas dehydration. Natural gas is sometimes saturated with water, which must be removed because it can form ice and plug different parts of pipeline gathering and transportation systems and processing plants. Water in a natural gas stream can also cause corrosion when combined with carbon dioxide or hydrogen sulfide in natural gas, and condensed water in the pipeline can raise inlet pipeline pressure, causing a greater pressure drop downstream. Dehydration of natural gas helps to avoid these potential issues and to meet downstream pipeline and end-user gas quality standards.

Natural gas treating and blending. Natural gas composition varies depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations can be high in carbon dioxide or hydrogen sulfide, which may cause significant damage to pipelines and is generally not acceptable to end-users. To alleviate the potential adverse effects of these contaminants, many pipelines regularly inject corrosion inhibitors into the gas stream. Additionally, to render natural gas with high carbon dioxide or hydrogen sulfide levels to downstream pipeline quality, pipelines may blend the gas with gas that contains low carbon dioxide or hydrogen sulfide levels, or arrange for treatment to remove carbon dioxide and hydrogen sulfide to levels that meet pipeline

quality standards. Natural gas can also contain nitrogen, which lowers the heating value of natural gas and must be removed to meet pipeline specifications.

Amine treating. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb these impurities from the gas. After mixing, gas and amine are separated, and the impurities are removed from the amine by heating. The treating plants are sized by the amine circulation capacity in terms of gallons per minute.

Natural gas processing. Natural gas processing involves the separation of natural gas into downstream pipeline quality natural gas and a mixed NGL stream. The principal component of natural gas is methane, but most natural gas also contains varying amounts of heavier hydrocarbon components, or NGLs. Natural gas is described as lean or rich depending on its content of NGLs. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use because it contains NGLs and impurities. Natural gas processing not only separates the dry natural gas from the NGLs that would interfere with downstream pipeline transportation or other uses of the natural gas, but also extracts hydrocarbon liquids that can have higher value as NGLs. Removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics.

Natural gas conditioning. Conditioning of natural gas is the process by which NGLs are removed from the natural gas stream by lowering the hydrocarbon dew point sufficiently to meet downstream gas pipeline quality specifications. Although similar to natural gas processing, conditioning involves removing only an absolute minimum amount of NGLs (typically the components of pentane and heavier products) from the gas stream. Conditioning involves significantly higher temperatures than cryogenic processing and consumes less fuel. Conditioning capability is beneficial during periods of unfavorable processing margins.

NGL fractionation. Fractionation is the process by which NGLs are separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. Stabilized condensate is primarily used as a refinery feedstock for the production of motor gasoline and other products.

NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. Fractionation takes advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off the top of the tower where it is condensed and routed to a pipeline or storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Because the fractionation process uses large quantities of heat, fuel costs are a major component of the total cost of fractionation.

Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users and utilities and to other pipelines.

NGL transportation. NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation used depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, consistent volumes of NGLs are to be delivered.

Risk Management

We are exposed to market risks such as changes in commodity prices and interest rates. We use derivative instruments to mitigate the effects of these risks. In general, we attempt to hedge against the effects of changes in commodity prices or interest rates on our cash flow and profitability so that we can continue to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes. For a discussion of our risk management activities, please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

Regulation

In the ordinary course of business, we are subject to various laws and regulations, as described below. We believe that compliance with existing laws and regulations will not materially affect our financial position. Although we cannot predict how new or amended laws or regulations that may be adopted would impact our business, such laws, regulations or amendments could increase our costs and could reduce demand for natural gas and NGLs or crude oil, thereby reducing demand for our services.

Industry Regulation

FERC Regulation of Intrastate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so FERC does not directly regulate the rates and terms of service associated with our operations. However, FERC’s regulations under the Natural Gas Policy Act of 1978 (the “NGPA”) and the Energy Policy Act of 2005 do affect certain aspects of our business and the market for our products.

Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. The Commodity Futures Trading Commission (the “CFTC”) also has authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas and NGLs, our gathering or transportation of these energy commodities and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, 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.

FERC has adopted market-monitoring and annual reporting regulations intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. FERC also requires certain major non-interstate natural gas pipelines to post, on a daily basis, capacity and scheduled flow information under regulations that became effective, as revised on rehearing, on October 1, 2010. Certain of our operations are subject to FERC reporting requirements, including daily internet posting of capacity and scheduled flow information, reporting of contract terms by intrastate Section 311 natural gas pipelines and reporting of aggregated annual volume and other information by natural gas wholesalers and purchasers.

FERC Regulation of NGL Pipelines. We own or operate NGL pipelines 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 (the “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.

Intrastate Natural Gas Pipeline Regulation. We own an intrastate natural gas transmission facility in Texas. To the extent it transports gas in interstate commerce, this facility is subject to regulation by the FERC under

Section 311 of the NGPA. Section 311 requires, among other things, that rates for such interstate service (which may be established by the applicable state agency, in our case the Texas Railroad Commission, or the “TRRC”) be “fair and equitable” and permits the FERC to approve terms and conditions of service.

Natural Gas Gathering Regulation. Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from FERC’s jurisdiction. We own or hold interests in a number of natural gas pipeline systems in Texas, Oklahoma and Wyoming that we believe meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts. Thus, we cannot guarantee that the jurisdictional status of our natural gas gathering facilities will remain unchanged.

In Texas, Oklahoma and Wyoming, the states in which our gathering operations take place, we are subject to state safety, environmental and service regulation. While our non-utility operations are not subject to direct state regulation of our gathering rates, we are required to offer gathering services on a non-discriminatory basis. In general, the non-discrimination requirement is monitored and enforced by each state based upon filed complaints.

We are also subject to state ratable take and common purchaser statutes in these states. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discriminating in favor of one producer over another producer or one source of supply over another source of supply.

State Utility Regulation. Some of our operations in Texas (specifically, our intrastate transmission pipeline and several of our gathering systems) are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally, the TRRC has authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. None of our operations in Oklahoma or Wyoming are regulated as public utilities by the Oklahoma Corporation Commission (“OCC”) or the Wyoming Public Service Commission (“WPSC”).

Sales of Natural Gas and NGLs. The prices at which we buy and sell natural gas currently are not subject to federal regulation, and except as noted above with respect to our gas utility operations, are not subject to state regulation. The prices at which we sell NGLs are not subject to federal or state regulation.

Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Environmental, Health and Safety Matters

Our operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, conditioning, transporting or fractionation of natural gas, NGLs, condensate and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:


	•	restricting the way we can handle or dispose of wastes;

	•	limiting or prohibiting construction and operating activities in environmentally sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

	•	requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operators; and

	•	enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.

We believe that our operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

The following is a summary of the more significant current environmental, health and safety laws and regulations to which our business operations are subject:

Hazardous Substances and Wastes. Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous waste.

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to strict and, under certain circumstances, joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources and for the costs of certain health studies.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, field compression and processing of natural gas, as well as the gathering of natural gas or crude oil. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been disposed of or released on or under some properties owned or leased by us or on or under other locations where such substances have been taken for disposal. Some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination) or perform remedial plugging or pit closure operations to prevent future contamination. As of December 31, 2010, we have not received notification that any of our properties has been determined to be a current Superfund site under CERCLA.

Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, and use specific emission control technologies to limit emissions. While we may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we currently do not believe that our operations will be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Climate Change. In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public heath and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles effective January 2, 2011 and thus triggered additional permitting requirements for GHG emissions from certain stationary sources. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. The EPA also published a final rule on November 30, 2010 expanding its existing GHG emissions reporting rule to include onshore natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate.

Water Discharges. Our operations are subject to the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including petroleum hydrocarbon discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by a permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties and significant remedial obligations.

Pipeline Safety. Our natural gas and NGL pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to hazardous liquids (including NGLs) pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Our pipelines are also 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”). The DOT, through the Pipeline and Hazardous Materials Safety Administration, has established a series of rules which require pipeline operators to develop and implement integrity management programs for natural gas and hazardous liquid pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. In addition, pursuant to authorization granted by PIPES, the DOT’s regulatory coverage extends to certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species or other ecological resources. Safety requirements imposed by this extended coverage include pipeline corrosion and third-party damage concerns but do not include pipeline integrity management criteria. Also, the TRRC and the OCC have adopted regulations similar to existing DOT regulations for intrastate natural gas and hazardous liquid gathering and transmission lines, while the Wyoming Public Service Commission has done the same only with respect to intrastate natural gas gathering and transmission lines.

Endangered Species. The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. While some of our facilities may be located in, or otherwise serve, areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. For example the U.S. Department of the Interior (“DOI”) recently considered listing the sage grouse, a ground-dwelling bird that inhabits portions of the Rocky Mountains region, including Wyoming, where we have natural gas gathering operations, as an endangered species under the ESA. An Endangered Species Act designation could result in broad conservation measures restricting or even prohibiting natural gas exploration and production and expansion of our natural gas gathering activities in affected areas. The

DOI determined that that sage grouse qualified for protection under the ESA but deferred listing it as endangered because of higher-priority listing commitments. Rather, Wyoming’s then-governor, Dave Freudenthal, issued an executive order in 2010 increasing the areas protected for the sage grouse some of which affect areas near Bighorn’s and Fort Union’s gathering systems. Developers of oil and natural gas activity in protected areas must demonstrate how their activities will not diminish sage grouse populations in these areas. Moreover, the federal Bureau of Land Management and the State of Wyoming are pursuing separate strategies to maintain and enhance sage grouse habitat.

Employee Health and Safety. We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Office Facilities

We lease our executive offices in Houston, Texas, Tulsa, Oklahoma, and Englewood, Colorado. We also lease property or facilities for some of our field offices. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

Employees

As of December 31, 2010, we, through our subsidiaries, CPNO Services, L.P. and ScissorTail, had 357 full-time employees and 7 part-time employees. None of our employees are covered by collective bargaining agreements. We consider our relations with our employees to be good.

Available Information

We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including us.

We also make available free of charge on or through our website (http://www.copanoenergy.com) or through our Investor Relations group (713-621-9547), our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website is not incorporated by reference into this report.


Item 1A.	*Risk Factors*

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operations could be adversely affected.

Risks Related to Our Business

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

We may not have sufficient cash each quarter to pay distributions at the current level. Under our limited liability company agreement, we set aside any cash reserve necessary for the conduct of our business before making a distribution to our unitholders. The amount of cash we have available for distribution is more a function of our cash flow rather than of our net income, 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.

The amount of cash we can distribute principally depends upon the cash we generate from operations, which will fluctuate from quarter to quarter based on, among other things:


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

	•	the amount and NGL content of the natural gas we process;

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

	•	the fees we pay to third parties for their services;

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

	•	the relationship between natural gas and NGL prices;

	•	the level of our operating costs and the impact of inflation on those costs; and

	•	the weather in our operating areas.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:


	•	the amount of capital we spend on projects, the profitability of such projects and the timing of the associated cash flow;

	•	our ability to borrow money and access capital markets;

	•	the cost of any acquisitions we make;

	•	the effectiveness of our hedging program and the creditworthiness of our hedging counterparties;

	•	our debt service requirements;

	•	fluctuations in our working capital needs;

	•	restrictions on distributions imposed by our revolving credit facility and the indentures governing our senior unsecured notes;

	•	restrictions on distributions by entities in which we own interests;

	•	the amount of cash reserves established by our Board of Directors for the proper conduct of our business; and

	•	prevailing economic conditions.

Some of the factors described above are beyond our control. If we decrease distributions, the market price for our units may be adversely affected.

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, natural gas prices at the Henry Hub in

Louisiana (which serves as the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange, or “NYMEX”) reached a low of $2.84 per MMBtu in September 2009 and ranged from $5.82 per MMBtu in January 2010 to $3.29 per MMBtu in November 2010. Based on average monthly Mt. Belvieu prices and our weighted-average product mix in Texas for 2010, NGL prices ranged from $50.61 per barrel in January 2010 to $38.26 per barrel in July 2010.

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:


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

	•	the level of domestic oil and natural gas production;

	•	storage levels for oil, natural gas, LNG and NGLs;

	•	the availability of imported oil, natural gas, LNG and NGLs;

	•	international demand for LNG, oil and NGLs;

	•	actions taken by foreign oil and gas producing nations;

	•	the availability of local, intrastate and interstate transportation systems for natural gas and NGLs;

	•	the availability of downstream NGL fractionation facilities;

	•	the availability and marketing of competitive fuels;

	•	the impact of energy conservation efforts; and

	•	the extent of governmental regulation and taxation.

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. We use commodity derivative instruments to hedge our exposure to commodity prices, but these instruments also are subject to inherent risks. Please read “— Our hedging activities do not eliminate our exposure to commodity price and interest rate risks and may reduce our cash flow and subject our earnings to increased volatility.”

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

Our business strategy contemplates pursuing capital projects and acquisitions, 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 projects or transactions 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 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 influencing our cost of capital are 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 and financing flexibility and impair our ability to fulfill our obligations.

We have substantial indebtedness. As of February 15, 2011 and in addition to liabilities related to our risk management activities, we had total indebtedness of $632.2 million, including our senior unsecured notes and our revolving credit facility, and available borrowing capacity under our revolving credit facility was approximately $400 million. 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, these obligations could:


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

	•	make it more difficult for us to satisfy our debt service requirements or comply with financial or other covenants in our debt agreements;

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

	•	result in higher interest expense if interest rates increase;

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

	•	place us at a disadvantage relative to any competitors that have proportionately less debt.

If we are unable to meet our debt service and other financial obligations or comply with our debt covenants, 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 sell assets on satisfactory terms, if at all. Failure to meet our debt service and other financial obligations could result in defaults under our debt agreements, which, if not cured or waived, would lead to 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.

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

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


	•	sell assets;

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

	•	make investments;

	•	incur or guarantee additional indebtedness or issue preferred units;

	•	create or incur certain liens;

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

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

	•	engage in transactions with affiliates;

	•	create unrestricted subsidiaries;

	•	enter into sale and leaseback transactions; and

	•	enter into letters of credit.

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 in the economy in general, or conduct operations.

In addition, 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 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash to us, and its lenders could accelerate its repayment obligations, both of 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 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:


	•	one or more of our lenders failed to meet its funding obligations;

	•	at the time we draw on our revolving credit facility, any of the representations or warranties or certain covenants included in the agreement is false in any material respect and the lenders elected to refuse to provide funding; or

	•	any lender refuses to fund its commitment for any reason, whether or not valid, and the other lenders elect not to provide additional funding to make up for the unfunded portion.

If we are unable to access funds under our revolving credit facility, we would need to meet our capital requirements using other sources which, depending on economic conditions, 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 expansion 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 in recent years, and the availability and cost of debt and equity capital are subject to general economic conditions and 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 not available 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. A general increase in 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 hedging activities do not eliminate our exposure to commodity price and interest rate risks 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 NGL volumes. We continue to have direct interest rate and commodity price risk with respect to the unhedged portions, and our hedging strategies cannot offset volume risk.

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.

Our hedging activity may be ineffective or adversely affect our cash flow and liquidity, our earnings or both because, among other factors:


	•	hedging can be expensive, particularly during periods of volatile prices or when hedging into extended future periods;

	•	our counterparty in the hedging transaction may default on its obligation to pay; and

	•	available hedges may not correspond directly with the risks against which we seek protection. For example:


	•	the duration of a hedge may not match the duration of the risk against which we seek protection;

	•	variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); and

	•	we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity.

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 recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

In July of 2010, the United States Congress adopted comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The financial reform legislation may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time pending promulgation of regulations by the Commodities Futures Trading Commission and the SEC. Even if we are not directly subject to such margin or clearing requirements, our counterparties may be subject to new capital, margin, clearing, and business conduct requirements imposed as a result of the new legislation, which may increase our transaction costs or make it more difficult to enter into hedging transactions on favorable terms. Accordingly, the new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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 provide service to our customers depends in part on the availability of third-party pipelines and other facilities, and because we do not own or operate these pipelines and facilities, their continuing operation or availability is not within our control. For example, we rely on Kinder Morgan’s Laredo-to-Katy pipeline to transport natural gas from many of our Texas gathering systems to, and Dow Hydrocarbon to take delivery of NGLs from, our Houston Central complex, and we rely on ONEOK Hydrocarbon to take delivery of NGLs from our Saint Jo plant and from several of our Oklahoma processing plants. We also depend on other third-party processing plants, pipelines and other facilities to provide our customers with processing, delivery, fractionation or transportation options.

Like us, these third-party service providers are subject to risks inherent in the midstream business, including capacity constraints, natural disasters and operational, mechanical or other hazards. For example, we believe that NGL fractionation and transportation facilities on which we depend are subject to increasing capacity constraints. Also, some third-party pipelines have minimum gas quality specifications that at times may limit or eliminate our transportation options.

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. A prolonged interruption or reduction of service on Kinder Morgan, Dow Hydrocarbon, ONEOK Hydrocarbon or another pipeline or facility on which we depend could hinder our ability to contract for additional gas supplies.

Because of the natural decline in production from existing wells, our success depends on our ability to continually obtain new supplies of natural gas and NGLs.

Our pipeline systems and processing or fractionation facilities are connected to or dependent on 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 inlet volumes at our processing plants, we must continually obtain new supplies of natural gas and NGLs. 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.

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. 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.

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 integrate our acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions potentially involve numerous risks, including:


	•	operating a significantly larger combined organization and adding operations;

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

	•	the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed on the anticipated timetable, or at all;

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

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

	•	failure to realize expected profitability or growth;

	•	failure to realize any expected synergies and cost savings;

	•	exposure to increased competition;

	•	coordinating geographically disparate organizations, systems and facilities;

	•	coordinating or consolidating information technology, compliance under the Sarbanes-Oxley Act of 2002 and other administrative or compliance functions; and

	•	a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.

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 make compliance with financial covenants under our debt agreements more difficult, and, if an acquisition’s performance does not improve, could ultimately require us to record an impairment of our interest in the acquired company or assets. Although our capitalization and results of operations may change significantly following an acquisition, you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

Our acquisitions could expose us to potential significant liabilities.

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 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 producers’ unwillingness 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 reserves connected to our pipeline systems is less than we anticipate and we are unable to secure additional sources of natural gas, the volumes of natural gas that we gather and process would likely decline. A sustained decline in natural gas volumes would 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.

Constructing new assets will subject us to risks that projects may not be completed on schedule or on budget and that anticipated natural gas supplies may not be available following completion of the projects. Our operating cash flows from our capital projects may not be immediate or meet our expectations.

One of the ways we grow our business is by constructing additions or modifications to our existing pipelines (including additional compression) and processing plants. We may also construct new facilities, either near our existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties beyond our control. 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, at the budgeted cost, or at all. Moreover, we may not receive any material increase in operating cash flow from a project for some time, particularly in the case of greenfield projects, or the cash flow we receive may not meet our expectations. We often rely on estimates of future production in deciding whether to construct additional or new facilities. 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 sufficient volumes to

achieve our expected investment return. We also may construct assets in reliance on firm capacity commitments by third-party facilities downstream of our facilities. If such third-party facilities are not available when we expect them, we could be adversely affected.

If we experience unanticipated or extended delays in generating operating cash flow from construction projects, we may need to reduce or reprioritize our capital budget in order to meet our capital requirements, and our cash flows and results of operations may be adversely affected.

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

We generally obtain new rights-of-way before constructing or extending pipelines and renew expiring rights-of-way associated with our existing assets. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other expansion opportunities. Additionally, it may become more expensive for us to obtain or renew rights-of-way. Increasing costs or otherwise burdensome terms for new or renewed rights-of-way could impair our ability to grow or adversely affect our results of operations.

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. Several of our pipelines in Texas are subject to regulation as gas utilities by the TRRC. The states in which we operate have complaint-based regulation of natural gas gathering activities. Natural gas producers, shippers and other affected parties may file complaints with state regulators relating to natural gas gathering access and discrimination with regard to rates and terms of service, or, with respect to our gas utility pipelines in Texas, challenging the rates we charge for utility transportation service. 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. A successful complaint, or new laws or regulatory rulings related to gathering, downstream quality specifications or natural gas utilities, could increase our costs or require us to alter our gathering or utility services charges and our business.

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 FERC pursuant to Section 311 of the NGPA. 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, or 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.

Our physical purchases and sales of natural gas and NGLs, our gathering or transportation of these energy commodities, and any related hedging activities, must comply with applicable 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.

These and other new laws and regulations or any administrative or judicial re-interpretations of existing laws, regulations or agreements could impose increased costs and administrative burdens on us, and our business, results

of operations and financial condition could be adversely affected. In addition, laws and regulations affecting producers to whom we provide our services could have adverse effects on us to the extent they affect production in our operating areas. For instance, the U.S. Supreme Court is adjudicating a dispute between the States of Montana and Wyoming over water rights in two rivers that flow through both states. Montana is asserting that Wyoming uses too much water from the Tongue and Powder Rivers pursuant to the Yellowstone River Compact, an agreement that both states entered into in 1950. Montana argues that the Compact applies to groundwater, and that coal bed methane production in Wyoming, which involves the pumping of large quantities of groundwater, is depleting the two rivers in violation of the Compact. Montana has asked the Supreme Court to declare Montana’s right to, and to order Wyoming to deliver, the waters of these two rivers to Montana in accord with the Compact. In a February 2010 ruling on Wyoming’s motion to dismiss, the special master appointed by the Supreme Court concluded that the Compact protects Montana from at least some forms of groundwater pumping but left the question of the exact circumstances under which groundwater pumping violates the Compact to subsequent proceedings in the case. Any decision by the Supreme Court that effectively limits the amount of groundwater pumped in connection with coal bed methane production in Wyoming may have significant adverse effects on natural gas production in affected areas of Wyoming and, correspondingly, on gathering services that Bighorn and Fort Union 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 rate and service 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 from time to time, 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. To the extent any of our NGL assets is found to be subject to FERC jurisdiction, 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.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs for producers and additional operating restrictions or delays affecting production of natural gas, which could adversely affect us.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, legislation was proposed in the recently ended session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the current session of Congress. Moreover, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, Wyoming, where we have natural gas gathering system operations, has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemical used in the hydraulic fracturing process. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could reduce demand for our gathering and processing or fractionation services.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our midstream services.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public heath and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles effective January 2, 2011 and thus triggered construction and operating permit review for GHG emissions from certain stationary sources. It is widely expected that facilities required to obtain permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. On November 30, 2010, the EPA published a final GHG emissions reporting rule relating to onshore oil and natural gas processing, transmission, storage, and distribution activities, which requires reporting beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time.

The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our midstream operations.

We may incur significant costs and liabilities resulting from pipeline safety and integrity programs and related compliance efforts.

We are subject to DOT safety regulations with respect to our natural gas lines and 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;

	•	mandatory inspections for all United States oil (including NGL) and natural gas transportation pipelines and gathering lines meeting certain operational risk and location requirements; and

	•	additional safety requirements applicable to certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified unusually sensitive areas, which address primarily corrosion and third-party damage concerns.

Although many of our natural gas facilities fall within a class that is not currently 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.

In response to recent major pipeline accidents, legislation has been introduced in Congress that would increase pipeline safety requirements. Among the changes being considered are new standards for excess flow and shutoff valves and public accessibility of pipeline information. Adoption of any new or expanded pipeline safety requirements could 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.

We are subject to environmental laws and regulations that may expose us to significant costs and liabilities.

Our operation of 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, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with pollution 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 as a result of our handling of natural gas, NGLs and other hydrocarbons, air emissions and waste water discharges related to our operations and historical industry operations, 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.

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:


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

	•	inadvertent damage from motor vehicles, construction or farm equipment;

	•	leaks of natural gas, NGLs and other hydrocarbons;

	•	operator error; and

	•	fires and explosions.

These risks could result in substantial losses due to personal 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 assets and operations are primarily concentrated in the Texas Gulf Coast and north Texas regions and in southwest Louisiana, central and eastern 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.

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:


	•	62.5% interest in Webb Duval;

	•	majority interest in Southern Dome;


	•	51% interest in Bighorn

	•	37.04% interest in Fort Union;

	•	50% interest in Eagle Ford Gathering; and

	•	50% interest in Liberty Pipeline Group.

Although we serve each of these entities as operator, managing member or both, certain substantive business decisions with respect to each 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 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 owners of any of these entities could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the entity involved and, in turn, the amounts and timing of cash from operations distributed to its 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.

Risks Related to Our Structure

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

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Law. Section 203 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, including common units and other equity securities that rank senior to common units, that we may issue at any time without the approval of our unitholders, and existing NASDAQ listing rules allow us to issue additional interests without unitholder approval so long as we do not exceed 20% of our common units then outstanding. In addition, our preferred units, which were approved by our common unitholders at a special meeting held in November 2010 and generally become convertible into common units beginning in July 2013, are entitled to in-kind payments of quarterly distributions for each quarter through the third quarter of 2013. We may elect to continue to pay preferred distributions in kind for each quarter through the third quarter of 2016. All preferred units that we issue in payment of quarterly preferred units in kind will be convertible into common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	your proportionate ownership interest in us will decrease;

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

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

	•	the market price of our common units may decline.

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

We have agreed to file a registration statement on Form S-3 to cover sales by TPG of all common units issuable upon conversion of our outstanding preferred units and additional preferred units that we issue as in-kind quarterly distributions. If TPG or a successor to its registration rights were to dispose of a substantial portion of these common 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.

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 our 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 our 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.

Increases in interest rates could adversely affect our unit price.

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.

Tax Risks to Common Unitholders

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 federal income tax purposes or we were to become subject to a material amount of entity-level taxation for state purposes, 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 publicly traded 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.

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, federal legislation that would eliminate pass-through tax treatment for certain publicly traded limited liability companies is proposed from time to time. We cannot predict whether any of these changes or other proposals 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 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.

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 in those units, 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 effective tax rate, and non-U.S. persons will be required to file U.S. 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 our common units.

To maintain the uniformity of the economic and tax characteristics of our common units, 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. Recently, however, the U.S. Treasury Department 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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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 lending 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 our filing two tax returns 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 calendar year, 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; rather, we would be treated as a new partnership for tax purposes. If we were 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 conduct 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 conduct business and own assets in several states, most of which currently impose a personal income tax. As we make acquisitions or expand our business, we may conduct business or own assets in other jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all of the unitholder’s required U.S. federal, state and local tax returns.


Item 1B.	*Unresolved Staff Comments*

None.


Item 2.	*Properties*

A description of our properties is provided in Item 1 of this report. Substantially all of our pipelines are constructed under rights-of-way granted by the apparent record landowners. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee.

Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with their use in the operation of our business.


Item 3.	*Legal Proceedings*

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings, except for proceedings described below. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, that would have a significant adverse effect on our financial position or results of operations.

As a result of our Cantera acquisition in October 2007, we acquired Cantera Gas Company LLC (“Cantera Gas Company,” formerly CMS Field Services, Inc. (“CMSFS”)). Cantera Gas Company is a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMSFS and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred before Cantera Resources, Inc. acquired CMSFS in June 2003 (the “CMS Acquisition”). The amount of liability, if any, against Cantera Gas Company is not reasonably estimable. Pursuant to the CMS Acquisition purchase agreement, CMS Gas Transmission has assumed responsibility for the defense of these claims, and Cantera Gas Company is fully indemnified by CMS Gas Transmission and its parent, CMS Enterprises Company, against any losses that Cantera Gas Company may suffer as a result of these claims.

PART II


Item 5.	*Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities*

Common Units

Our common units, which represent limited liability company interests in us, are listed on The NASDAQ Global Select Market (“NASDAQ”), under the symbol “CPNO.” On February 18, 2011, the closing market price for our common units was $35.45 per unit, and there were approximately 279 common unitholders of record.

The following table shows the high and low sales prices per common unit, as reported by NASDAQ, and the distribution per common unit for the periods indicated.


	Price of				Cash
	Common Units				Distribution
	High		Low		Per Common Unit

2010:
Quarter Ended December 31	$	33.77	$	27.30	$	0.575
Quarter Ended September 30	$	29.43	$	24.49	$	0.575
Quarter Ended June 30	$	27.89	$	21.53	$	0.575
Quarter Ended March 31	$	25.62	$	20.70	$	0.575
2009:
Quarter Ended December 31	$	24.39	$	15.95	$	0.575
Quarter Ended September 30	$	19.28	$	14.40	$	0.575
Quarter Ended June 30	$	17.42	$	12.94	$	0.575
Quarter Ended March 31	$	17.21	$	11.14	$	0.575

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 from operating surplus, as defined in our limited liability company agreement. Available cash consists generally of all cash on hand at the end of the fiscal quarter, less retained cash reserves established by our Board of Directors. Our credit agreement does not provide for the type of working capital borrowings that would be eligible for inclusion in available cash or operating surplus.

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

Our ability to distribute cash is subject to a number of risks and uncertainties, some of which are beyond our control. Please read Item 1A, “Risk Factors — Risks Relating to Our Business.” If we do not have sufficient cash to pay a distribution as well as satisfy our operational and financial obligations, then our Board of Directors can reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments. For a discussion of the restrictions on distributions imposed by our revolving credit facility and the indentures governing our senior unsecured notes, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Series A Convertible Preferred Units

On July 21, 2010, we issued 10,327,022 Series A convertible preferred units (“preferred units”) in a private placement to an affiliate of TPG Capital for gross proceeds of $300 million. The preferred units were priced at $29.05 per unit, a 10% premium to the 30-day volume-weighted average closing price of our common units on July 19, 2010, two trading days before the date we issued the preferred units. For a description of the terms of our preferred units, please read “Member’s Capital and Distributions — Series A Convertible Preferred Units” in Note 6 to our consolidated financial statements included in Item 8 of this report.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian Total Return Index on November 9, 2004 (the day our units began trading on NASDAQ), and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.


	November 9,		December 31,
	2004		2005		2006		2007		2008		2009		2010

Copano (CPNO)	$	100	$	180	$	288	$	367	$	127	$	289	$	434
Alerian MLP Total Return Index (AMZX)	$	100	$	113	$	142	$	160	$	101	$	178	$	242
S&P 500 Index (SPX)	$	100	$	107	$	122	$	126	$	78	$	96	$	108

Notwithstanding anything to the contrary set forth in any of our previous or future filings under the Securities Act of 1933 or the Exchange Act that might incorporate this report or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

Issuer Purchases of Equity Securities

None.

Recent Sales of Unregistered Securities

None.


Item 6.	*Selected Financial Data*

Selected Historical Consolidated Financial Information

The following table shows our selected historical consolidated financial information for the periods and as of the dates indicated. This information is derived from, should be read together with and is qualified in its entirety by reference to, our historical audited consolidated financial statements and the accompanying notes included in Item 8 of this report. The selected financial information should also be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2010			2009		2008		2007⁽¹⁾		2006
	(In thousands, except per unit data)

Summary of Operating Results:
Revenue⁽²⁾	$	995,164		$	820,046	$	1,454,419	$	1,064,515	$	860,272
(Loss) income from continuing operations	$	(8,681	)	$	20,866	$	55,922	$	61,381	$	65,114
Basic (loss) income per common unit from
continuing operations⁽³⁾	$	(0.37	)	$	0.39	$	1.15	$	1.44	$	1.77
Diluted (loss) income per common unit from
continuing operations⁽³⁾	$	(0.37	)	$	0.36	$	0.97	$	1.32	$	1.75
Other Financial Information:
Cash distributions per common unit	$	2.30		$	2.30	$	2.17	$	1.73	$	1.29


	December 31,
	2010		2009		2008		2007⁽¹⁾		2006
	(In thousands)

Balance Sheet Information:
Total assets	$	1,906,993	$	1,867,412	$	2,013,665	$	1,769,083	$	839,058
Long-term debt		592,736		852,818		821,119		630,773		255,000
Members’ capital		1,154,757		860,026		1,037,958		894,136		472,586


(1)		Our summary financial information as of and for the year ended December 31, 2007 includes results attributable to our Cimmarron acquisition from May 1, 2007 through December 31, 2007 and our Rocky Mountains segment from October 1, 2007 (the date we acquired Cantera) through December 31, 2007.

(2)		Our summary financial data as of and for the years ended December 31, 2009, 2008 and 2007 excludes the results attributable to our crude oil pipeline and related activities, as they are classified as discontinued operations. Please read Note 13, “Discontinued Operations,” to the audited consolidated financial statements included in Item 8 of this report.

(3)		Net income per unit is based on the weighted average of total equivalent units outstanding during the periods presented. Prior periods have been adjusted to reflect the two-for-one split of our outstanding common units effective March 30, 2007.


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

You should read the following discussion of our financial condition and results of operations in conjunction with the historical consolidated financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical consolidated financial statements included in Item 8 of this report. In addition, you should review “— Forward-Looking Statements” included in this Item 7 and “Risk Factors” included in Item 1A of this report for information regarding forward-looking statements made in this discussion and certain risks inherent in our business, as well as Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

Overview

Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission 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.


	•	Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration, treating, conditioning or processing and marketing. Our Texas segment also provides NGL fractionation and transportation through our Houston Central complex and our NGL pipelines. In addition, our Texas segment includes a processing plant located in southwest Louisiana and our equity investments in Webb Duval, Eagle Ford Gathering and Liberty Pipeline Group.

	•	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 equity investment in Southern Dome, and through September 2009, included a crude oil pipeline.

	•	Our Rocky Mountains segment includes our equity investments in Bighorn and Fort Union and provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas and compressor rental services.

Corporate and other relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with “— How We Evaluate Our Operations” and “— How We Manage Our Operations” below. Many of the factors affecting our business are beyond our control and are difficult to predict.

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are influenced by natural gas and NGL prices and by drilling activity. Generally, prices affect the cash flow and profitability of our Texas and Oklahoma segments directly and, to the extent that they influence the level of drilling activity, prices also affect all of our segments indirectly. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

Natural gas prices affect the long-term growth and sustainability of our business because they influence natural gas exploration and production activity. Commodity price fluctuations are among the factors that natural gas producers consider as they schedule drilling projects. Producers typically increase drilling activity when natural gas prices are sufficient to make drilling and production economic and, depending on the severity and duration of an unfavorable pricing environment, they may suspend drilling and completion activity to the degree they have become uneconomic. These changes in drilling activity are reflected in production volumes (and in turn, in our throughput volumes) only gradually because of the time required to drill, complete and attach new wells (or if drilling is

declining, because of continuing production from already-completed wells). Delays between drilling and production for completion and attachment of new wells can range from a few days in areas with minimal completion and attachment processes to as long as 18 months in areas where extensive dewatering is required.

The level at which drilling and production become economic depends on a variety of factors in addition to natural gas prices. For producers of rich gas who share in the benefits of improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset if NGL prices are consistently high relative to natural gas prices. Strong crude oil prices could also support increased production of casinghead natural gas associated with oil production.

We believe generally that strong NGL pricing environments support growth in rich gas drilling; however, the effects of prices are subject to other factors, some of which could diminish a producers’ ability and incentives to drill. These factors include the availability of capital and the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir, among other things. Some producers can rely on commodity price hedging to support drilling activity when prices are less favorable. Also, producers may drill when they otherwise would not to the extent that drilling activity is necessary to maintain their leasehold interests or under the terms of their capital commitments.

Natural gas and NGL prices generally are influenced by a variety of factors that affect supply and demand. These factors include regional drilling activity, available pipeline capacity, the severity of winter and summer weather (and other factors that influence consumption), natural gas storage levels, competing supplies (such as liquefied natural gas imports), and NGL transportation and fractionation capacity. Many of these factors are in turn dependent on overall economic activity. Economic recovery in the U.S. has been slow, and the strength and sustainability of the recovery remain uncertain. A renewed slowdown in economic activity would likely result in declines in natural gas and NGL prices and reduced drilling activity.

Fourth-Quarter Commodity Prices Overall. Natural gas prices overall averaged below $4 per MMBtu for much of the fourth quarter of 2010 but increased in December, and average NGL prices and crude oil prices increased steadily throughout the quarter.

Pricing Trends in Texas. NGL prices in Texas increased steadily in the fourth quarter, and natural gas prices increased in October and December but decreased in November. Through February 17, 2011, NGL prices increased as compared to the fourth quarter of 2010 while natural gas prices remained flat. First-of-the-month prices for natural gas on the Houston Ship Channel index were $4.10 per MMBtu for January and $4.30 per MMBtu for February 2011, and the spot price at February 17, 2011 was $3.88 per MMBtu. Weighted-average daily prices for NGLs at Mt. Belvieu as of February 17, 2011, based on our fourth-quarter 2010 product mix, were $53.28 per barrel.

The following graph and table summarize prices for crude oil on NYMEX and for natural gas and NGLs on the primary indices we use for Texas pricing.

Texas Prices for Crude Oil, Natural Gas and NGLs⁽¹⁾


(1)		Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on our weighted-average product mix at Mt. Belvieu for the period indicated.


	Annual Data for Texas:
							Quarterly Data for Texas:
	2008		2009		2010		Q1 2010		Q2 2010		Q3 2010		Q4 2010
Houston Ship Channel ($/MMBtu)	$	8.67	$	3.78	$	4.38	$	5.36	$	4.04	$	4.33	$	3.78
Mt. Belvieu ($/barrel)	$	60.61	$	33.51	$	44.68	$	47.66	$	43.14	$	40.16	$	48.03
NYMEX crude oil ($/barrel)	$	99.75	$	62.09	$	79.53	$	78.72	$	78.03	$	76.20	$	85.17
Service throughput (MMBtu/d)		686,791		619,615		595,641		582,958		559,876		590,116		648,941
Plant inlet (MMBtu/d)		610,249		539,633		504,810		457,233		469,019		516,949		574,616
NGLs produced (Bbls/d)		16,150		17,959		18,718		15,339		18,382		19,685		21,388
Segment gross margin (in thousands)	$	142,723	$	103,620	$	128,682	$	27,165	$	31,751	$	31,218	$	38,548

Pricing Trends in Oklahoma. NGL prices in Oklahoma increased steadily in the fourth quarter of 2010, and natural gas prices declined midway in the quarter and increased significantly in December. Through February 17, 2011, NGL prices remained flat while natural gas prices decreased slightly. First-of-the-month prices for natural gas on the CenterPoint East index were $3.96 per MMBtu for January and $4.21 per MMBtu for February 2011, and the spot price at February 17, 2011 was $3.79 per MMBtu. Weighted-average daily prices for NGLs at Conway as of February 17, 2011, based on our fourth-quarter product mix, were $46.52 per barrel.

The following graph and table summarize prices for crude oil on NYMEX and for natural gas and NGLs on the primary indices we use for Oklahoma pricing.

Oklahoma Prices for Crude Oil, Natural Gas and NGLs⁽¹⁾


(1)		Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on our weighted-average product mix at Conway for the period indicated.


	Annual Data for Oklahoma:						Quarterly Data for Oklahoma:
	2008		2009		2010		Q1 2010		Q2 2010		Q3 2010		Q4 2010
CenterPoint East ($/MMBtu)	$	7.11	$	3.27	$	4.19	$	5.22	$	3.86	$	4.14	$	3.53
Conway ($/barrel)	$	51.28	$	29.65	$	40.21	$	44.44	$	36.34	$	36.53	$	43.91
NYMEX crude oil ($/barrel)	$	99.75	$	62.09	$	79.53	$	78.72	$	78.03	$	76.20	$	85.17
Service throughput (MMBtu/d)		238,836		262,259		261,636		248,784		259,972		270,184		267,353
Plant inlet (MMBtu/d)		156,057		163,474		156,181		152,190		156,204		156,676		154,257
NGLs produced (Bbls/d)		15,126		15,977		16,251		15,334		16,653		16,541		16,480
Segment gross margin (in thousands)⁽²⁾	$	133,112	$	76,686	$	93,617	$	24,275	$	21,821	$	23,010	$	24,511


(2)		Segment gross margin results exclude activities attributable to our crude oil pipeline and related assets discussed in Note 13, “Discontinued Operations,” to our consolidated financial statements included in Item 8 of this report.

Basis Trends. The average basis differential was flat at $3.97 per barrel for the fourth quarter of 2010 as compared to the third quarter of 2010. Prices for purity ethane accounted for 65% of the basis differential. For January 2011, this basis differential averaged $4.41 per barrel, and at February 17, 2011, the basis differential was $6.76 per barrel. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.25 per MMBtu for the fourth quarter, which was an increase of $0.06 per MMBtu as compared with the third quarter. The basis differential was $0.14 per MMBtu for January 2011 and $0.09 per MMBtu at February 17, 2011.


	Annual Data for Rocky Mountains:						Quarterly Data for Rocky Mountains:
	2008		2009		2010		Q1 2010		Q2 2010		Q3 2010		Q4 2010
CIG ($/MMBtu)	$	6.24	$	3.07	$	3.92	$	5.14	$	3.61	$	3.50	$	3.42
Pipeline throughput (MMBtu/d)⁽¹⁾		945,925		975,785		907,809		931,319		900,047		913,730		886,568
Segment gross margin (in thousands)⁽²⁾	$	5,877	$	3,254	$	4,440	$	1,103	$	1,148	$	1,091	$	1,098


(1)		Includes 100% of Bighorn and Fort Union.

(2)		Excludes results and volumes associated with our equity interests in Bighorn and Fort Union.

Fourth Quarter 2010 Drilling and Production Activity.


	•	Drilling. We saw increased drilling activity in the fourth quarter of 2010, primarily from producers targeting the Woodford Shale behind our Mountains systems in Oklahoma and the north Barnett Shale Combo play behind our Saint Jo plant in Texas. Drilling activity has also increased significantly in the Eagle Ford Shale in Texas, where we continued to work to secure additional long-term supply contracts. Drilling activity in the Rocky Mountains has remained low, and activity in other areas of Texas and Oklahoma remained flat compared to the third quarter of 2010.

	•	Volumes. Our overall service throughput volumes for the fourth quarter of 2010 increased compared to the third quarter of 2010, primarily reflecting the effects of drilling activity in shale gas plays and higher third-party volumes at our Houston Central complex.

Rich gas activity in Texas has increased steadily since mid-2009, but it has decreased slightly in Oklahoma. Based on our conversations with Oklahoma producers, we believe that a significant amount of lean gas activity has been supported by commodity hedging and by improved well completion technology, which allows producers to realize higher production for the same drilling costs. Additionally, producers may be drilling in order to maintain their leasehold interests or to recover costs they have already incurred. Volumes in the Rocky Mountains have continued to decline due to limited drilling activity in the Powder River Basin.


	•	Outlook. So long as NGL and crude prices generally remain strong relative to natural gas prices, we anticipate continued drilling growth in rich gas areas such as the Eagle Ford Shale and the north Barnett Shale Combo play. Although the Woodford Shale has been an exception, we anticipate continued lower drilling activity in most areas that produce lean gas, for example the Powder River Basin, until natural gas prices increase.

Commodity prices continue to show some volatility, and improvements in drilling activity, particularly in areas where producers employ conventional drilling techniques, remain sporadic. We expect that many producers who rely on conventional drilling, produce mainly lean gas, or both, will wait to see sustained increases in natural gas prices before resuming significant drilling activity; however, other factors such as commodity hedges, improved well completion technology or the need to maintain leasehold interests will also influence their decisions.

Other Industry Trends. NGL transportation and fractionation facilities continue to experience capacity constraints, which generally results in higher NGL transportation and fractionation costs for parties that do not have contractually fixed costs. Growing rich natural gas volumes from the Eagle Ford Shale are placing additional pressure on existing transportation capacity for NGLs, condensate and crude oil, while transportation costs for heavier NGL products in Texas remain higher due to reduced demand for these products and lack of broad pipeline infrastructure. Capacity constraints could result in higher transportation and fractionation costs and lower NGL prices due to an excess of supply. These effects could limit the benefits producers receive from rich gas production and eventually could affect the level of drilling activity in rich gas plays.

Please read Item 1A, “Risk Factors — Risks Related to our Business.”

Factors Affecting Operating Results and Financial Condition

Our results for 2010 reflect the continued effects of limited drilling that followed 2009’s weaker pricing environment. We and some of the joint ventures in which we own interests have continued to experience flat or declining volumes, particularly from most lean gas areas, due to low drilling activity. Our volumes were also reduced by interruptions of operations at our Houston Central complex to complete connections for new purity ethane and propane lines, to prepare for the start-up of our fractionator and to perform maintenance.

Our results also are beginning to reflect the offsetting effect of rich gas drilling that has followed improvement in NGL prices. Relatively strong NGL prices in Oklahoma and Texas combined with lower natural gas prices in Texas during 2010 have continued to benefit our processing margins. Our combined operating segment gross margins increased 24% compared to 2009. Our results for the fourth quarter also benefited from our fractionation operations at the Houston Central complex, which began in April 2010, and significant volume growth at our Saint Jo plant; however, these benefits were offset somewhat by downtime at our Houston Central complex for maintenance in November and December 2010.

Consistent with our business strategy, we have used derivative instruments to mitigate the effects of commodity price fluctuations on our cash flow and profitability so that we can continue to meet our debt service and capital expenditure requirements, and our distribution objectives. For much of 2009, cash settlements from our commodity hedge portfolio helped to offset the decline in operating revenues attributable to lower commodity prices. For 2010, improvements in commodity prices have increased our operating segment cash flow and reduced our cash flow from commodity hedge settlements. For 2010, we received $33.6 million in net cash settlements from our commodity hedge portfolio, compared to $68.7 million for 2009.

How We Evaluate Our Operations

We believe that investors benefit from access to the various financial and operating measures that our management uses in evaluating our performance. These measures include the following: (i) throughput volumes; (ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) total distributable cash flow. Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below.

Throughput Volumes. Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes delivered to our plants and flowing through our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is significantly influenced by the volume of natural gas delivered to the plant, the NGL content of the natural gas, the quality of the natural gas and the plant’s recovery capability. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs and losses associated with our pipeline operations, these costs are frequently passed on to our producers under contractual agreements.

It is also important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes. In monitoring our pipeline volumes, managers of our Oklahoma and Texas segments evaluate what we refer to as service throughput, which consists of two components:


	•	the volume of natural gas transported or gathered through our pipelines, which we call pipeline throughput; and

	•	the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines, excluding any volumes already included in our pipeline throughput.

In our Texas segment, we also compare pipeline throughput and service throughput to evaluate the volumes generated from our pipelines, as opposed to third-party pipelines. In Oklahoma, because no gas is delivered to our wholly owned plants other than by our pipelines, pipeline throughput and service throughput are equivalent.

In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered using our firm capacity gathering agreements with Fort Union and volumes transported using our firm transportation agreements with WIC. We also regularly assess the pipeline throughput of Bighorn and Fort Union.

Segment Gross Margin and Total Segment Gross Margin. We define segment gross margin as an operating segment’s revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs we purchase and costs for transportation of our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to more easily identify operational or other issues within a segment. With respect to our Texas and Oklahoma segments, our management analyzes segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn and Fort Union.

In Texas, increases in natural gas prices or decreases in NGL prices generally have a negative impact on margins, and, conversely, a reduction in natural gas prices or an increase in NGL prices generally has a positive impact. However, when we operate our Houston Central complex in conditioning mode, increases in natural gas prices have a positive impact on our margins. Our Oklahoma margins are, on the whole, positively correlated with NGL prices and natural gas prices. The profitability of our Rocky Mountains operations is not directly affected by commodity prices. Substantially all of our Rocky Mountains contract portfolio, as well as Bighorn’s and Fort Union’s contract portfolios, consist of fixed-fee arrangements providing for an agreed gathering fee per unit of natural gas throughput. Our revenues from these arrangements are directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent that low commodity prices discourage drilling activity and result in declining volumes, however, our revenues under these arrangements will also decline.

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.

Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for oil, natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon the market demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Both segment gross margin and total segment gross margin are reviewed monthly for consistency and trend analysis.

Operations and Maintenance Expenses. The most significant portion of our operations and maintenance expenses consists of direct labor, insurance, repair and maintenance, utilities and contract services. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. We monitor operations and maintenance expenses to assess the impact of such costs on the profitability of a particular asset or group of assets and to evaluate the efficiency of our operations.

General and Administrative Expenses. Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. To help ensure the appropriateness of our general and administrative expenses, we monitor such expenses through comparison with general and administrative expenses incurred by similar midstream companies and with the annual financial plan approved by our Board of Directors.

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation, amortization and impairment expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval, Eagle Ford Gathering and Southern Dome), our management also calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, our management determines adjusted EBITDA by adding to EBITDA (i) the amortization expense attributable to the difference between our carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate’s depreciation and amortization expense which is proportional to our ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs which is proportional to our ownership interest in that unconsolidated affiliate.

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.

Total Distributable Cash Flow. We define total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense relating to the option component of our risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v) the subtraction of equity in earnings from unconsolidated affiliates and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and our line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows we generate (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders. Using total distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

Although we have previously reported both distributable cash flow and total distributable cash flow, we determined that total distributable cash flow is a better measure of the rate at which cash available for distribution is generated by our operations than distributable cash flow, which does not add back the amortization expense relating to the option component of our risk management portfolio. Total distributable cash flow should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Reconciliation of total segment gross margin to operating income:
Operating income	$	45,777		$	72,355		$	105,703
Add:
Operations and maintenance expenses		53,487			51,477			53,824
Depreciation and amortization		62,572			56,975			52,916
General and administrative expenses		40,347			39,511			45,571
Taxes other than income		4,726			3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates		20,480			(4,600	)		(6,889	)

Total segment gross margin	$	227,389		$	219,450		$	254,144

Reconciliation of EBITDA and adjusted EBITDA to net income (loss):
Net income (loss)	$	(8,681	)	$	23,158		$	58,213
Add:
Depreciation and amortization⁽¹⁾		62,572			57,539			53,154
Interest and other financing costs		53,605			55,836			64,978
Provision for income taxes		931			794			1,249

EBITDA		108,427			137,327			177,594
Add:
Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment		43,126			19,203			19,116
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		8,466			9,493			5,863
Copano’s share of interest and other financing costs incurred by our equity method investments		1,452			1,303			3,259

Adjusted EBITDA	$	161,471		$	167,326		$	205,832

Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
Cash flow provided by operating activities	$	123,598		$	141,318		$	89,924
Add:
Cash paid for interest and other financing costs		49,850			51,881			60,510
Equity in earnings (loss) from unconsolidated affiliates		(20,480	)		4,600			6,889
Distributions from unconsolidated affiliates		(22,416	)		(20,931	)		(22,460	)
Risk management activities		(13,344	)		(30,155	)		27,037
Changes in working capital and other		(8,781	)		(9,386	)		15,694

EBITDA		108,427			137,327			177,594
Add:
Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment		43,126			19,203			19,116
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		8,466			9,493			5,863
Copano’s share of interest and other financing costs incurred by our equity method investments		1,452			1,303			3,259

Adjusted EBITDA	$	161,471		$	167,326		$	205,832

Reconciliation of net income (loss) to total distributable cash flow:
Net income (loss)	$	(8,681	)	$	23,158		$	58,213
Add:
Depreciation and amortization⁽¹⁾		62,572			57,539			53,154
Amortization of commodity derivative options		32,378			36,950			32,842
Amortization of debt issue costs		3,755			3,955			4,467
Equity-based compensation		10,388			8,252			7,789
Distributions from unconsolidated affiliates		25,955			29,684			25,830
Unrealized (gain) loss associated with line fill contributions and gas imbalances		1,538			(2,145	)		592
Unrealized loss (gain) on derivative activity		(984	)		(6,879	)		12,751
Deferred taxes and other		(280	)		271			1,927
Less:
Equity in (earnings) loss from unconsolidated affiliates		20,480			(4,600	)		(6,889	)
Maintenance capital expenditures		(9,563	)		(9,728	)		(11,769	)

Total distributable cash flow⁽²⁾	$	137,558		$	136,457		$	178,907


(1)		Includes activity related to the discontinued operations of the crude oil pipeline and related assets discussed in Note 13, “Discontinued Operations,” to our consolidated financial statements included in Item 8 of this report

(2)		Prior to any retained cash reserves established by our Board of Directors.

How We Manage Our Operations

Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models and standardized processing margin, (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting and (iv) imbalance monitoring and control.

Economic Models and Standardized Processing Margin. We use our economic models to determine (i) whether we should reduce the ethane extracted from natural gas processed by some of our processing plants and third-party plants and (ii) whether we should process natural gas, reject ethane or condition natural gas at our Houston Central complex and Saint Jo plant.

To isolate and consistently track changes in commodity price relationships and their impact on our Texas segment’s results from its processing operations, we calculate a hypothetical “standardized” processing margin at our Houston Central complex. Our processing margin refers to the difference between the market value of:


	•	NGLs we extract in processing; and

	•	the thermal equivalent of natural gas attributable to those NGLs plus the natural gas consumed as fuel in extracting those NGLs.

Our “standardized” processing margin is based on a fixed set of assumptions, with respect to NGL composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices, such as volumes, changes in NGL composition, recovery rates and variable contract terms. However, we believe this calculation is representative of the current operating commodity price environment of our Texas processing operations, and we use this calculation to track commodity price relationships. Our standardized processing margins averaged $0.5784, $0.3903 and $0.4336 per gallon during the years ended December 31, 2010, 2009 and 2008, respectively. The average standardized processing margin for the period from January 1, 1989 through December 31, 2010 is $0.1674 per gallon.

Flow and Transaction Monitoring Systems. We use automated systems that track commercial activity on each of our Texas segment pipelines and monitor the flow of natural gas on all of our pipelines. In our Texas segment, we designed and implemented software that tracks each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our pipeline assets. Additionally, we use automated Supervisory Control and Data Acquisition (“SCADA”) systems, which assist management in monitoring and operating our Texas segment. These SCADA systems allow us to monitor our assets at remote locations and respond to changes in pipeline operating conditions. For our Oklahoma segment, we electronically monitor pipeline volumes and operating conditions at certain key points along our pipeline systems and use a SCADA system on some of our gathering systems. Bighorn, which our Rocky Mountains segment operates, also uses a SCADA system.

Producer Activity Evaluation and Reporting. We monitor producer drilling and completion activity in our areas of operation to identify anticipated changes in production and potential new well connection opportunities. The continued connection of natural gas production to our pipeline systems is critical to our business and directly impacts our financial performance. Using a third-party electronic reporting system, we receive daily reports of new drilling permits and completion reports filed with the state regulatory agency that governs these activities in Texas and Oklahoma. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel. These processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines. In all our operating segments, we meet with producers to better understand their drilling and production plans, and to obtain drilling schedules, if available, to assist us in anticipating future activity on our pipelines.

Imbalance Monitoring and Control. We continually monitor volumes received and volumes delivered on behalf of third parties to ensure we remain within acceptable imbalance limits during the calendar month. We seek

to reduce imbalances because of the inherent commodity price risk that results when receipts and deliveries of natural gas are not balanced concurrently. We have implemented “cash-out” provisions in many of our transportation and gathering agreements to reduce this commodity price risk. Cash-out provisions require that any imbalance that exists between a third party and us at the end of a calendar month is settled in cash based upon a pre-determined pricing formula. These provisions ensure that imbalances under such contracts are not carried forward from month-to-month and revalued at higher or lower prices.

Our Contracts

We seek to execute contracts with producers and shippers that provide us with stable cash flows even in adverse natural gas and NGL pricing environments. Our existing contract mix reflects pricing terms (including fee-based, percentage-of-proceeds, percentage-of-index and keep-whole) with varying levels of commodity price sensitivity. Our focus in executing new contracts is on increasing our fee-based revenues, which we believe will contribute to the stability of our cash flow.

In addition to compensating us for gathering, transportation, processing, conditioning or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration or other services. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter in the form of “processing upgrade” payments during periods in which processing margins exceed an agreed-upon amount.

The table below summarizes our gross margin attributable to each of the most common pricing terms in our contract portfolio, as a percentage of our quarterly total segment gross margin and our share of the gross margin from each of our unconsolidated affiliates.


Contract Pricing	Q1 2010			Q2 2010			Q3 2010			Q4 2010

Fee-based		27	%		33	%		37	%		38	%
Percentage-of-proceeds/index		39	%		31	%		30	%		32	%
Keep-whole		36	%		33	%		29	%		34	%
Net hedging⁽¹⁾		(2	)%		3	%		4	%		(4	)%


(1)		Net impact of our commodity derivative instruments to total segment gross margin.

Generally, non-fee-based pricing terms carry some commodity sensitivity, while fee-based pricing is only indirectly affected by commodity prices. Substantially all of our Rocky Mountains contracts are fee-based arrangements. Our contracts in Oklahoma and Texas often reflect a combination of pricing terms. An example of combined pricing terms would be a percentage-of-proceeds contract that also allows us to charge a treating fee for removing contaminants from natural gas.

Fee-Based Pricing. Under fee-based pricing, producers or shippers pay us an agreed amount per unit of throughput to gather or transport their natural gas and perform other services such as NGL fractionation, transportation and marketing. The revenue we earn from fixed-fee arrangements is directly related to the volume of natural gas or NGLs that flows through our systems and is not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices suppresses drilling and results in a decline in volumes, our fee-based revenues would also decline.

Commodity Sensitive Pricing. Our profitability under the following pricing terms is subject to changes in the prices of natural gas and NGLs.


	•	Percentage-of-Proceeds. Under percentage-of-proceeds arrangements, we generally gather and process natural gas and sell the residue gas and NGL volumes on behalf of a producer at index-related prices. We remit to the producer an agreed upon percentage of the proceeds from the sales of residue gas and NGLs. Under these types of arrangements, our revenues and gross margins increase as natural gas and NGL prices increase and decrease as natural gas and NGL prices decrease.

	•	Percentage-of-Index. Under percentage-of-index arrangements, we purchase natural gas at a percentage discount to a specified index price. We then gather, deliver and resell the natural gas at an index-based price.


		The gross margins we realize under percentage-of-index arrangements decrease when natural gas prices are low and increase when natural gas prices are high.


	•	Keep-Whole. Under keep-whole arrangements, we receive natural gas from a producer or third-party transporter, process or condition the gas and keep the extracted NGLs for our own account, and sell the NGLs at market prices. We then return to the producer or transporter an amount of residue gas that is equal, in terms of Btu value, to the amount of wellhead gas we received — in other words an amount that keeps the producer or transporter whole.

Because extracting NGLs from natural gas during processing or conditioning reduces the Btu content of the natural gas, we must purchase natural gas at market prices for return to producers or third-party transporters. Our revenues and gross margins under keep-whole arrangements increase as NGL prices increase relative to natural gas prices, and decrease as natural gas prices increase relative to NGL prices. When natural gas prices are high and NGL prices are low, we are generally able to reduce our commodity price exposure by limiting the amount of NGLs we extract from natural gas, which we can do through ethane rejection or conditioning.

The terms of any individual contract will depend on a variety of factors, including gas quality, pressures of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, gas quality, downstream transporter gas quality specifications, our expansion in regions where some types of contracts are more common and other market factors.

Our Contracts with Kinder Morgan. We use Kinder Morgan as a transporter because our Houston Central complex straddles its 30-inch-diameter Laredo-to-Katy pipeline, which allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central complex and downstream markets. Kinder Morgan’s pipeline also delivers to the Houston Central complex natural gas for its own account, which we refer to as “KMTP Gas.” Under agreements with Kinder Morgan and with other producers or transporters whose gas Kinder Morgan has delivered to us, we process or condition the gas and sell the NGLs to third parties at market prices. Under our processing agreement with Kinder Morgan, after processing or conditioning KMTP Gas, we make up for the reduction in Btu content resulting from extracting NGLs from the natural gas stream using natural gas that we purchase from producers at market prices. Our processing agreement with Kinder Morgan also provides that we make a processing payment to Kinder Morgan during periods of favorable processing margins, which allows Kinder Morgan to share in the profitability of processing gas. During periods of unfavorable processing margins, Kinder Morgan instead pays us the lesser of (i) the difference between the processing margin and a specified threshold or (ii) a fixed fee per Mcf of KMTP Gas.

We also have a gas transportation agreement and a related gas sales agreement with Kinder Morgan. Each of our agreements with Kinder Morgan extends through December 31, 2024, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior written notice, in the case of the processing and gas transportation agreements, or 30 days’ prior written notice, in the case of the sales agreement.

For the year ended December 31, 2010, approximately 79% of the natural gas volumes processed or conditioned at our Houston Central complex were delivered to the plant through the Kinder Morgan Laredo-to-Katy pipeline, while the remaining 21% were delivered directly to the plant from our Houston Central gathering systems. Of the volumes delivered from the Laredo-to-Katy pipeline, approximately 39% were from our gathering systems or under our contracts, while 61% were “KMTP Gas.” Of the total NGLs extracted at the plant during this period, 26% originated from KMTP Gas, and 74% from our south Texas gathering systems, including our Houston Central gathering systems.

Forward-Looking Statements

This report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this report, including, but not limited to, those under “— Our Results of Operations” and “— Liquidity and Capital Resources” are forward-looking statements.

Statements included in this report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. 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:


	•	the volatility of prices and market demand for natural gas, crude oil and NGLs, and for products derived from these commodities;

	•	our ability to continue to connect new sources of natural gas supply and the NGL content of new supplies;

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

	•	our ability to retain key customers and contract with new customers;

	•	our ability to access or construct new NGL fractionation and transportation capacity;

	•	the availability of local, intrastate and interstate transportation systems and other facilities for natural gas and NGLs;

	•	our ability to meet in-service dates and cost expectations for construction projects;

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

	•	our ability to access our revolving credit facility and to obtain additional financing on acceptable terms;

	•	the effectiveness of our hedging program;

	•	general economic conditions;

	•	force majeure situations such as the loss of a market or facility downtime;

	•	the effects of government regulations and policies; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, 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 set forth under Item 1A, “Risk Factors.” All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, 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.

Our Results of Operations


	Year Ended December 31,
	2010			2009			2008
	($ In thousands)

Total segment gross margin⁽¹⁾⁽²⁾	$	227,389		$	219,450		$	254,144
Operations and maintenance expenses⁽²⁾		53,487			51,477			53,824
Depreciation and amortization⁽²⁾		62,572			56,975			52,916
General and administrative expenses		40,347			39,511			45,571
Taxes other than income		4,726			3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates^(3)(4)(5)(6)		20,480			(4,600	)		(6,889	)

Operating income⁽²⁾⁽³⁾		45,777			72,355			105,703
Gain on retirement of unsecured debt		—			3,939			15,272
Interest and other financing costs, net		(53,527	)		(54,634	)		(63,804	)
Provision for income taxes		(931	)		(794	)		(1,249	)
Discontinued operations, net of tax		—			2,292			2,291

Net income (loss)		(8,681	)		23,158			58,213
Preferred unit distributions		(15,188	)		—			—

Net (loss) income to common units	$	(23,869	)	$	23,158		$	58,213

Total segment gross margin:
Texas	$	128,682		$	103,620		$	142,723
Oklahoma⁽²⁾		93,617			76,686			133,112
Rocky Mountains⁽⁷⁾		4,440			3,254			5,877

Segment gross margin⁽²⁾		226,739			183,560			281,712
Corporate and other⁽⁸⁾		650			35,890			(27,568	)

Total segment gross margin⁽¹⁾⁽²⁾	$	227,389		$	219,450		$	254,144

Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu)	$	0.59		$	0.46		$	0.57
Oklahoma:
Service throughput ($/MMBtu)⁽²⁾	$	0.98		$	0.80		$	1.52
Volumes:
Texas:⁽⁹⁾
Service throughput (MMBtu/d)⁽¹⁰⁾		595,641			619,615			686,791
Pipeline throughput (MMBtu/d)		328,967			290,627			314,252
Plant inlet volumes (MMBtu/d)		504,810			539,633			610,249
NGLs produced (Bbls/d)		18,718			17,959			16,150
Oklahoma:⁽¹¹⁾
Service throughput (MMBtu/d)⁽¹⁰⁾		261,636			262,259			238,836
Plant inlet volumes (MMBtu/d)		156,181			163,474			156,057
NGLs produced (Bbls/d)		16,251			15,977			15,126
Capital Expenditures:
Maintenance capital expenditures	$	9,563		$	9,728		$	11,769
Expansion capital expenditures		120,941			61,424			169,056

Total capital expenditures	$	130,504		$	71,152		$	180,825

Operations and maintenance expenses:
Texas	$	29,236		$	27,960		$	29,950
Oklahoma⁽²⁾		23,955			23,469			23,874
Rocky Mountains		296			48			—

Total operations and maintenance expenses⁽²⁾	$	53,487		$	51,477		$	53,824


(1)		Total segment gross margin is a non-GAAP financial measure. See “— How We Evaluate Our Operations” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.

(2)		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 Item 8 of this report.


(3)		During the three months ended June 30, 2010, we recorded a $25 million non-cash impairment charge relating to our investment in Bighorn primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the CIG forward price curve.

(4)		Includes results and volumes associated with our interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 907,809 MMBtu/d, 975,785 MMBtu/d and 945,925 MMBtu/d for 2010, 2009 and 2008, respectively.

(5)		Includes results and volumes associated with our interest in Southern Dome. For 2010, plant inlet volumes for Southern Dome averaged 12,522 MMBtu/d and NGLs produced averaged 449 Bbls/d. For 2009, plant inlet volumes for Southern Dome averaged 13,137 MMBtu/d and NGLs produced averaged 478 Bbls/d. For 2008, plant inlet volumes for Southern Dome averaged 9,923 MMBtu/d and NGLs produced averaged 364 Bbls/d.

(6)		Includes results and volumes associated with our interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 54,879 MMBtu/d, 78,160 MMBtu/d and 91,342 MMBtu/d for 2010, 2009 and 2008, respectively.

(7)		Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union, volumes transported using our firm capacity agreements with WIC and compressor rental services provided to Bighorn. Excludes results and volumes associated with our interest in Bighorn and Fort Union.

(8)		Corporate and other includes results attributable to our commodity risk management activities.

(9)		Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 491,732 MMBtu/d and NGLs produced averaged 17,827 Bbls/d for 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 525,413 MMBtu/d and NGLs produced averaged 16,810 Bbls/d for 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 596,535 MMBtu/d and NGLs produced averaged 14,715 Bbls/d for 2008 for plants owned by the Texas segment. Excludes volumes associated with our interest in Webb Duval.

(10)		“Service throughput” means the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines plus our “pipeline throughput,” which is the volume of natural gas transported or gathered through our pipelines.

(11)		Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties. For 2010, plant inlet volumes averaged 119,415 MMBtu/d and NGLs produced averaged 13,181 Bbls/d for plants owned by the Oklahoma segment. For 2009, plant inlet volumes averaged 126,776 MMBtu/d and NGLs produced averaged 13,044 Bbls/d for plants owned by the Oklahoma segment. For 2008, plant inlet volumes averaged 114,142 MMBtu/d and NGLs produced averaged 11,570 Bbls/d for plants owned by the Oklahoma segment. Excludes volumes associated with our interest in Southern Dome.

Year Ended December 31, 2010 Compared To Year Ended December 31, 2009

Net loss, which is prior to deducting in-kind preferred unit distributions, decreased to $8.7 million for 2010 compared to net income of $23.2 million for 2009. Primary drivers of this year over year decrease include (a) a $27.7 million non-cash impairment charge in 2010 related to our investments in Bighorn and Webb Duval resulting from a weak Rocky Mountains pricing environment for natural gas and lack of drilling activity in Wyoming’s Powder River Basin and dry natural gas areas in south Texas, (b) a $3.9 million gain in 2009 on the retirement of debt and (c) $2.9 million of income in 2009 related to our crude oil operations sold in October 2009 and other non-recurring income, offset by higher total segment gross margin reflecting average NGL price increases of 36% on the Conway index and 33% on the Mt. Belvieu index and lower interest expense associated with our outstanding debt.

Net loss to common units after deducting $15.2 million of in-kind preferred unit distributions on our Series A convertible preferred units issued in July 2010 totaled $23.9 million, or $0.37 per unit on a diluted basis, for 2010 compared to net income to common units of $23.2 million, or $0.40 per unit on a diluted basis, for 2009. Weighted

average diluted units outstanding totaled 63.9 million for 2010 as compared to 58.0 million for the same period in 2009.

Texas Segment Gross Margin. Texas segment gross margin was $128.7 million for 2010 compared to $103.6 million for 2009, an increase of $25.1 million, or 24%. Texas segment gross margin per unit of service throughput increased $0.13 per MMBtu to $0.59 per MMBtu for 2010 compared to $0.46 per MMBtu for 2009, reflecting 33% higher NGL prices, the impact of our fractionation facilities for a full quarter and an increase of pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays. The increase in segment gross margin was partially offset by a decline of 4% in service throughput for 2010 and higher average natural gas prices, which increased 16% compared to 2009. The Texas segment’s gathering and NGL production increased 13% and 4%, respectively, and processed volumes decreased 6% during 2010. The increase in NGL production is due to the producers’ continued focus on producing rich gas because of the current beneficial pricing environment for NGLs and reflects a 131% increase of volumes behind our Saint Jo plant in the north Barnett Shale Combo play. Processed volumes decreased because very limited volumes were available to be processed at our Lake Charles plant. Please read “— Trends and Uncertainties — Commodity Prices and Producer Activity” and “— Our Contracts.” We started the fractionator at our Houston Central complex in late April 2010, which reduced our third party fractionation costs and enabled us to begin charging fractionation fees to producers, resulting in an increase to our gross margin of $7.5 million during 2010.

Oklahoma Segment Gross Margin. Oklahoma segment gross margin was $93.6 million for 2010 compared to $76.7 million for 2009, an increase of $16.9 million, or 22%. The increase in segment gross margin resulted primarily from period-over-period increases in average natural gas and NGL prices of 28% and 36%, respectively, and a 2% increase in NGL production. Oklahoma segment gross margin per unit of service throughput increased $0.18 per MMBtu to $0.98 per MMBtu for 2010 compared to $0.80 per MMBtu for 2009. The increase in segment gross margin was partially offset by a decrease in plant inlet volumes of 4%. Service throughput remained flat between the periods. For 2010, plant inlet volumes at our Paden plant decreased 11% compared to 2009 primarily as a result of normal production declines on the Stroud gathering system. Please read “— Trends and Uncertainties — Commodity Prices and Producer Activity” and “— Our Contracts.”

Rocky Mountains Segment Gross Margin. Rocky Mountains segment gross margin was $4.4 million for 2010 compared to $3.3 million for 2009, an increase of $1.1 million, or 33%. This increase is primarily the result of increased compressor rental income from Bighorn.

Corporate and Other. Corporate and other includes our commodity risk management activities and was a $0.6 million gain for 2010 compared to a $35.9 million gain for 2009, a decrease of $35.2 million. The gain for 2010 includes $33.6 million of net cash settlements received on expired commodity derivative instruments offset by $0.6 million of unrealized loses on our commodity derivative instruments and $32.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments. The gain for 2009 includes $68.7 million of net cash settlements received on expired commodity derivative instruments and $4.1 million of unrealized mark-to-market gains on our commodity derivative instruments offset by $37.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $53.5 million for 2010 compared to $51.5 million for 2009. The 4% increase is attributable primarily to increased personnel, compensation and benefits costs due to our expanding operations which was partially offset by a reduction in our Oklahoma segment’s compressor rental costs.

Depreciation and Amortization. Depreciation and amortization totaled $62.6 million for 2010 compared with $57.0 million for 2009, an increase of 10%. This increase relates primarily to additional depreciation and amortization resulting from capital expenditures made subsequent to September 30, 2009, including expenditures relating to the fractionation facility at our Houston Central complex, the expansion of our Saint Jo plant and the construction of the DK pipeline in Texas.

General and Administrative Expenses. General and administrative expenses totaled $40.3 million for 2010 compared to $39.5 million for 2009. The 2% increase consists primarily of a $2.2 million increase in personnel, compensation and benefits costs and a $0.5 million increase in deferred equity compensation offset by a

$0.9 million decrease in acquisition costs, a $0.7 million increase in management fees received from our unconsolidated affiliates and a $0.3 million gain on the sale of assets.

Interest and Other Financing Costs. Interest and other financing costs totaled $53.6 million for 2010 compared to $55.8 million for 2009, a decrease of $2.2 million, or 4%. Interest expense related to our revolving credit facility totaled $5.1 million (including net settlements paid under our interest rate swaps of $5.1 million and net of $3.4 million of capitalized interest) and $8.2 million (including net settlements paid under our interest rate swaps of $5.4 million and net of $3.4 million of capitalized interest) for 2010 and 2009, respectively. Interest and other financing costs for 2010 includes unrealized mark-to-market gains of $1.6 million on undesignated interest rate swaps compared to unrealized mark-to-market gains of $2.7 million for the same period in 2009. Amortization of debt issue costs totaled $3.8 million and $4.0 million for 2010 and 2009, respectively. Average borrowings under our credit arrangements for 2010 and 2009 were $689.6 million and $848.8 million with average interest rates of 10.0% and 7.2%, respectively. Please read “— Liquidity and Capital Resources.”

Year Ended December 31, 2009 Compared To Year Ended December 31, 2008

Net income decreased by 60% to $23.2 million, or $0.40 per unit on a diluted basis, for 2009 compared to net income of $58.2 million, or $1.01 per unit on a diluted basis, for 2008. The primary drivers of this year over year decrease includes (a) a decrease in total segment gross margin of $34.7 million, consisting of a $98.2 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 42% on the Conway index and 45% on the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $63.5 million from commodity risk management activities, (b) an increase in depreciation, amortization and impairment expenses of $4.1 million primarily related to expanded operations in north Texas (c) a decrease of $11.3 million attributable to lower gain on the retirement of debt in 2009, (d) an increase in taxes other than income taxes of $0.7 million; and (e) a decrease of $2.3 million in equity in earnings of unconsolidated affiliates primarily as a result of a noncash impairment charge associated with inactive pipelines owned by Bighorn, of which our portion totaled $1.8 million, partially offset by (a) a decrease in general and administrative expenses of $6.1 million and operations and maintenance expenses of $2.4 million primarily related to reduced bad debt expense and successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees (b) a decrease of $9.2 million in interest expense primarily related to (i) a noncash mark-to-market gain on interest rate swaps for 2009 of $2.8 million compared to a $10.0 million loss in 2008, a change of $12.8 million, and (ii) reduced amortization expense related to debt issuance costs of $0.6 million, offset by an increase in interest paid of $4.2 million as a result of increased average outstanding borrowings offset by lower average interest rates between the periods, and (c) a decrease in income taxes of $0.4 million.

Texas Segment Gross Margin. Texas segment gross margin was $103.6 million for 2009 compared to $142.7 million for 2008, a decrease of $39.1 million, or 27%. The decrease in segment gross margin was primarily attributable to a decline in average NGL prices, which decreased 45% from 2008, a 10% decline in service throughput and a 12% decline in plant inlet volume from 2008. Volumes originating from the Texas segment and delivered to the plant decreased approximately 10% from 2008. The decrease in Texas segment gross margin was partially offset by lower average natural gas prices, which decreased 56% compared to 2008. The Texas segment gross margin per unit of service throughput decreased $0.11 per MMBtu to $0.46 per MMBtu for 2009, compared with $0.57 per MMBtu for 2008. The decrease in segment gross margin per unit of service throughput was attributable to the decrease in the realized prices for NGLs. Please read “— Trends and Uncertainties — Commodity Prices and Producer Activity” and “— Our Contracts.”

Oklahoma Segment Gross Margin. Oklahoma segment gross margin was $76.7 million for 2009 compared to $133.1 million for 2008, a decrease of $56.4 million, or 42%. The decrease in segment gross margin resulted primarily from period over period decreases in average natural gas and NGL prices of 54% and 42%, respectively. The Oklahoma segment gross margin per unit of service throughput decreased $0.73 per MMBtu to $0.80 per MMBtu for 2009 compared with $1.52 per MMBtu for 2008. The reduction in segment gross margin was partially offset by increases in NGLs produced, plant inlet volumes and service throughput of 6%, 5% and 10%, respectively. NGLs produced at the Paden plant increased 14% during 2009 as compared to 2008. The increase in throughput is primarily attributable to the residual effects of drilling activity initiated during the favorable pricing environment in early 2008. Please read “— Trends and Uncertainties.” The Oklahoma segment included our crude oil pipeline

activities through September 30, 2009. The segment gross margin results above exclude $2.6 million and $3.3 million related to our crude oil pipeline activities for 2009 and 2008, respectively. Please read “— Trends and Uncertainties — Commodity Prices and Producer Activity” and “— Our Contracts.”

Rocky Mountains Segment Gross Margin. Rocky Mountains segment gross margin was $3.3 million for 2009 compared to $5.9 million for 2008, a decrease of $2.6 million, or 44%. This decrease is primarily the result of lower volumes, which in 2009 were largely attributable to unfavorable commodity pricing environment as producers cut back drilling programs and temporarily ceased production on marginal wells in response to weaker natural gas prices, and is slightly offset by compressor fee income for the rental of compressors to Bighorn beginning in May 2009.

Corporate and Other. Corporate and other includes our commodity risk management activities and was a gain of $35.9 million for 2009 compared to losses of $27.6 million for 2008. The gain for 2009 includes $68.7 million of net cash settlements received on expired commodity derivative instruments and $4.1 million of unrealized mark-to-market gains on our commodity derivative instruments offset by $37.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments. The loss for 2008 includes $32.8 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $2.8 million of unrealized mark-to-market losses on our commodity derivative instruments, offset by $8.0 million of net cash settlements received on expired commodity derivative instruments.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $51.5 million for 2009 compared to $53.8 million for 2008. The 4% decrease is attributable to decreases of $0.4 million in our Oklahoma segment and $1.9 million in our Texas segment primarily due to our cost control efforts and decreased costs for chemicals, utilities and repair and maintenance.

Depreciation, Amortization and Impairment. Depreciation, amortization and impairment totaled $57.0 million for 2009 compared to $52.9 million for 2008, an increase of 8%. This increase relates primarily to additional depreciation and amortization recognized due to capital expenditures made subsequent to December 31, 2008 including expenditures relating to construction of our Saint Jo plant.

General and Administrative Expenses. General and administrative expenses totaled $39.5 million for 2009 compared with $45.6 million for 2008. The 13% decrease consists primarily of (i) a $5.3 million reduction in personnel, consultants, insurance, compensation and benefits costs, (ii) a reduction in legal and accounting fees of $2.1 million, (iii) reduction in costs of preparing and processing tax K-1s to unitholders of $0.3 million and (iv) an increase of $0.1 million in the management fees that we received from our affiliated entities. These reductions in costs were partially offset by (i) an increase of $0.8 million in expenses associated with acquisition initiatives, (ii) non-cash compensation expense of $0.9 million related to amortization of the fair value of restricted units, phantom units, unit options and unit appreciation rights issued under our long-term incentive plan.

Interest and Other Financing Costs. Interest and other financing costs totaled $55.8 million for 2009 compared with $65.0 million for 2008, a decrease of $9.2 million, or 14%. Interest expense related to our revolving credit facility totaled $8.2 million (including net settlements paid under our interest rate swaps of $5.4 million and net of $3.4 million of capitalized interest) and $8.0 million (including net settlements paid under our interest rate swaps of $1.8 million and net of $3.5 million of capitalized interest) for 2009 and 2008, respectively. Interest and other financing costs for 2009 includes unrealized mark-to-market gains of $2.7 million on undesignated interest rate swaps. Interest and other financing costs for 2008 includes unrealized mark-to-market losses of $10.0 million on undesignated interest rate swaps. Interest expense on our senior unsecured notes increased to $46.5 million for 2009 from $42.5 million in 2008 primarily as a result of issuing $300 million of senior unsecured notes on May 16, 2008 partially offset by interest savings as a result of retiring $67.8 million of senior unsecured notes from November 2008 through March 2009. Amortization of debt issue costs totaled $4.0 million and $4.5 million for 2009 and 2008, respectively. Average borrowings under our credit arrangements for 2009 and 2008 were $848.8 million and $720.7 million with average interest rates of 7.2% and 7.9%, respectively. Please read “— Liquidity and Capital Resources.”

Gain on Unsecured Debt Retirement. During 2009, we repurchased and retired $18.2 million aggregate principal amount of our 7.75% senior unsecured notes due 2018 using available cash and borrowings under our

revolving credit facility. During the fourth quarter of 2008, we repurchased and retired a face amount of $32.3 million principal of our 7.75% senior unsecured notes due 2018 and $17.3 million principal of our 8.125% senior unsecured notes due 2016 using available cash and borrowing under our revolving credit facility. As a result of repurchasing the notes below par value, we recognized a gain of $3.9 million and $15.3 million for the years ended December 31, 2009 and 2008, respectively.

Cash Flows

The following table summarizes our cash flows for each of the periods indicated as reported in the historical consolidated statements of cash flows found in Item 8 of this report.


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Net cash provided by operating activities	$	123,598		$	141,318		$	89,924
Net cash used in investing activities		(156,730	)		(70,967	)		(198,855	)
Net cash provided by (used in) financing activities		48,370			(89,343	)		99,950

Our cash flows are affected by a number of factors, some of which we cannot control. These factors include industry and economic conditions, as well as conditions in the financial markets, prices and demand for our services, volatility in commodity prices or interest rates, effectiveness of our hedging program, operational risks and other factors.

Operating Cash Flows. Net cash provided by operating activities was $123.6 million for 2010 compared to $141.3 million for 2009. The decrease in cash provided by operating activities of $17.7 million was attributable to the following changes:


	•	risk management activities used an additional $16.6 million of cash flow for the year ended December 31, 2010 as compared to the year ended December 31, 2009, primarily because we purchased commodity derivative instruments at a total cost of $19.8 million during the year ended December 31, 2010, whereas in the year ended December 31, 2009, we did not purchase commodity derivative instruments;

	•	a $6.1 million decrease in working capital for the year ended December 31, 2010 compared with the year ended December 31, 2009;

partially offset by:


	•	a $3.5 million decrease in interest payments for the year ended December 31, 2010 compared to the year ended December 31, 2009 as a result of lower average borrowings; and

	•	a $1.5 million increase in cash distributions received from certain of our unconsolidated affiliates (Bighorn and Fort Union) in the year ended December 31, 2010 compared to the year ended December 31, 2009.

Net cash provided by operating activities was $141.3 million for 2009 compared to $89.9 million for 2008. The increase in cash provided by operating activities of $51.4 million was attributable to the following changes:


	•	risk management activities provided an additional $57.2 million of cash flow for 2009 as compared to 2008, primarily because we purchased commodity derivative instruments totaling $6.9 million during 2009, whereas in 2008, we purchased $60.2 million of commodity derivative instruments;

partially offset by:


	•	cash distributions received from our unconsolidated affiliates (Bighorn, Fort Union, Webb Duval and Southern Dome) were $1.5 million lower in 2009 compared to 2008; and

	•	interest payments for 2009 were $4.3 million higher compared to 2008 as a result of issuing $300 million of senior unsecured notes in May 2008 partially offset by interest savings as a result of retiring $67.8 million of senior unsecured notes from November 2008 through March 2009.

Investing Cash Flows. Net cash used in investing activities was $156.7 million for 2010. Investing activities for 2010 included (i) $127.7 million of capital expenditures related to expansion of our Saint Jo plant and construction of upstream gathering lines, right-of-way acquisition, construction of the DK pipeline and start up of our fractionator at the Houston Central complex in Texas, and completion of the Burbank plant and installation of treating and compression facilities in Oklahoma, as well as constructing well interconnects to attach volumes in new areas, and (ii) $33.0 million of investments in Eagle Ford Gathering, Bighorn and Fort Union offset by (i) $3.5 million of distributions from Bighorn and Southern Dome in excess of equity earnings and (ii) other investing activities of $0.4 million.

Net cash used in investing activities was $71.0 million for 2009. Investing activities for 2009 included (i) $79.3 million of capital expenditures related to the construction of our Saint Jo plant and related projects, progress payments for the purchase of compression and constructing well interconnects to attach volumes in new areas, (ii) $4.2 million of investment in Bighorn, and (iii) other investing activities of $2.4 million, offset by (i) $8.8 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings and (ii) $6.1 million of proceeds from the sale of assets, primarily relating to our crude oil pipeline operations.

Net cash used in investing activities was $198.9 million for 2008. Investing activities for 2008 included (i) $174.5 million of capital expenditures related to the expansion and modification of our Paden plant, progress payments for the purchase of compression, construction of the Saint Jo plant, bolt-on pipeline acquisitions and constructing well interconnects to attach volumes in new areas, (ii) $26.8 million of investment in Bighorn and Fort Union and (iii) escrow cash and other investing activities of $1.0 million, offset by $3.4 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings and other.

Financing Cash Flows. Net cash provided by financing activities totaled $48.4 million during 2010 and included (i) proceeds from our private placement of Series A convertible preferred units net of underwriting discounts and commissions and fees of $285.3 million, (ii) net proceeds from our public offering of common units in 2010 (including units issued upon the underwriters’ exercise of their option to purchase additional units) of $164.3 million and (iii) proceeds from the exercise of unit options of $5.4 million offset by (i) net repayments under our revolving credit facility of $260 million, (ii) distributions to our unitholders of $145.5 million, and (iii) deferred financing costs of $1.0 million.

Net cash used in financing activities totaled $89.3 million during 2009 and included (i) borrowings under our revolving credit facility of $70.0 million and (ii) proceeds from the exercise of unit options of $0.7 million offset by (i) the retirement of $14.3 million aggregate principal amount of our 8.125% senior unsecured notes due 2016 and (ii) distributions to our unitholders of $125.7 million and (iii) the repayment of $20.0 million of outstanding borrowings under our revolving credit facility.

Net cash provided by financing activities totaled $100.0 million during 2008 and included (i) borrowings under our revolving credit facility of $279.0 million, (ii) issuance of our senior unsecured notes due 2018 of $300.0 million, (iii) capital contributions of $4.1 million from our pre-IPO Investors to fulfill their G&A expense reimbursement obligations and (iv) proceeds from the exercise of unit options of $1.1 million, offset by (i) repayments under our debt arrangements of $373.3 million, including the retirement of a total $34.3 million of our senior unsecured notes due 2016 and 2018 (ii) distributions to our unitholders of $104.2 million and (iii) deferred financing costs of $6.7 million.

Liquidity and Capital Resources

Sources of Liquidity. Cash generated from operations, borrowings under our revolving credit facility and funds from equity and debt offerings are our primary sources of liquidity. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on our revolving credit facility and senior unsecured notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our revolving credit facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions.

We believe that our cash from operations, cash on hand and our revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the next 12 months. If our plans change or our assumptions prove inaccurate, or if we make further acquisitions, we may need to raise additional capital.

Acquisitions and organic expansion have been, and our management believes will continue to be, key elements of our business strategy. In addition, we continue to consider opportunities for strategic greenfield projects. We intend to finance growth projects primarily through the issuance of debt and equity. Generally, we believe that over the long term, our cost of equity capital relative to master limited partnerships, or MLPs, of similar size will be favorable because, unlike many of our competitors that are MLPs, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as per-unit cash distributions increase.

The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate larger acquisitions or capital projects, we will require access to additional capital on competitive terms. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets, and other financial and business factors, many of which are beyond our control.

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


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

	•	expansion capital expenditures, which are capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance.

During 2010, our capital expenditures totaled $130.5 million, consisting of $9.6 million of maintenance capital and $120.9 million of expansion capital. We funded our capital expenditures with funds from operations and borrowings under our revolving credit facility. Expansion capital expenditures were related to the construction of gathering lines upstream of our Saint Jo plant, expansion of the Saint Jo plant, right-of-way acquisition, construction of the DK pipeline in Texas, start up of our fractionator at the Houston Central complex, completion of the Burbank plant and installation of treating and compression facilities in Oklahoma, as well as constructing well interconnects to attach volumes in new areas. Based on our current scope of operations, we anticipate incurring approximately $12 million to $14 million of maintenance capital expenditures over the next 12 months. We anticipate incurring approximately an additional $274 million in expansion capital expenditures in 2011 enhancing the capabilities and capacities of our current asset base.

Investment in Unconsolidated Affiliates. During 2010, our capital contributions to our unconsolidated affiliates totaled $33.0 million and consisted primarily of contributions to Eagle Ford Gathering for its initial construction of the Eagle Ford Gathering system. We anticipate making additional cash contributions to Eagle Ford Gathering and Liberty Pipeline Group of approximately $144 million related to remaining construction and completion of the Eagle Ford Gathering system, construction of the Liberty pipeline and to our Rocky Mountains unconsolidated affiliates.

Cash Distributions. The amount needed to pay the current distribution of $0.575 per unit, or $2.30 per unit annualized, to our common unitholders is as follows (in thousands):


	One Quarter		Four Quarters

Common units⁽¹⁾	$	38,456	$	153,823


(1)		Includes distributions on restricted common units and phantom units issued under our long-term incentive plan. Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of February 1, 2011, we had 59,952 outstanding restricted units and 879,513 outstanding phantom units.

Contractual Cash Obligations. A summary of our contractual cash obligations as of December 31, 2010, is as follows:


	Payment Due by Period
	Total		Less than						More than 5
Type of Obligation	Obligation		1 Year		1-3 Years		3-5 Years		Years
	(In thousands)

Long-term debt	$	592,190	$	—	$	10,000	$	—	$	582,190
Interest⁽¹⁾		282,891		46,443		92,668		92,734		51,046
Gathering, transportation and fractionation firm commitments		219,817		18,345		47,445		46,394		107,633
Operating leases		9,333		3,170		2,012		1,451		2,700

Total contractual cash obligations⁽²⁾	$	1,104,231	$	67,958	$	152,125	$	140,579	$	743,569


(1)		These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2010, the fair value of our interest rate swap contracts, which expire between January 2011 and October 2012, totaled $7.0 million.

(2)		These amounts exclude capital expenditures we have committed to approved capital projects.

Our Indebtedness

As of December 31, 2010 and 2009, our aggregate outstanding indebtedness totaled $592.2 million and $852.2 million, respectively, and we were in compliance with our financial debt covenants under our revolving credit facility and our incurrence covenants under the indentures governing our senior unsecured notes.

Credit Ratings. Moody’s Investors Service has assigned a Corporate Family rating of Ba3 with a negative outlook, a B1 rating for our senior unsecured notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a stable outlook and a B+ rating for our senior unsecured notes.

Revolving Credit Facility. As of December 31, 2010, we had $10 million in outstanding borrowings under our $550 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent.

Our revolving credit facility matures on October 18, 2012 and includes 28 lenders with commitments ranging from $1 million to $60 million, with the largest commitment representing 10.9% of the total commitments. Future borrowings under the facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restriction so long as we are in compliance with its terms, including the financial covenants described below. Our revolving credit facility provides for up to $50 million in standby letters of credit. As of December 31, 2010 and 2009, we had no letters of credit outstanding. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position.

Our revolving credit facility obligations are secured by first priority liens on substantially all of our assets and the assets of our wholly owned subsidiaries (except for equity interests in Fort Union and certain equity interests acquired with the Cimmarron acquisition), all of which are guarantors under the revolving credit facility. Our less

than wholly owned subsidiaries have not pledged their assets as security or guaranteed our obligations under the revolving credit facility.

Annual interest under the revolving credit facility is determined, at our election, by reference to (i) the British Bankers Association LIBOR rate (“LIBOR”), plus an applicable margin ranging from 1.25% to 2.50%, or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin ranging from 0.25% to 1.50%. The effective average interest rate on borrowings under the revolving credit facility for 2010, 2009 and 2008 was 8.9%, 4.8% and 6.5%, respectively, and the quarterly commitment fee on the unused portion of the revolving credit facility for those periods, respectively, was 0.25%, 0.25% and 0.25%. Interest and other financing costs related to the revolving credit facility totaled $5.7 million, $8.3 million and $11.8 million for 2010, 2009 and 2008, respectively.

The revolving credit facility contains various covenants (including certain subjective representations and warranties) that, subject to exceptions, limit our and subsidiary guarantors’ ability to grant liens; make loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the revolving credit facility limits our and our subsidiary guarantors’ ability to incur additional indebtedness, subject to exceptions, including (i) purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.

The revolving credit facility also contains financial covenants, which, among other things, require us and our subsidiary guarantors, on a consolidated basis, to maintain:


	•	a minimum EBITDA to interest expense ratio (using four quarters’ EBITDA as defined under the revolving credit facility) of 2.5 to 1.0; and

	•	a maximum total debt to EBITDA ratio of 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).

At December 31, 2010, our ratio of total debt to EBITDA was 3.03x, and our ratio of EBITDA to interest expense was 3.75x. Based on our ratio of total debt to EBITDA at December 31, 2010, we have approximately $400 million of available borrowing capacity under the revolving credit facility before we reach the maximum total debt to EBITDA ratio of 5.0 to 1.0.

Our revolving credit facility also contains customary events of default, including the following:


	•	failure to pay any principal when due, or within specified grace periods, any interest, fees or other amounts;

	•	failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to grace periods in some cases;

	•	default on the payment of any other indebtedness in excess of $5 million, or in the performance of any obligation or condition with respect to such indebtedness, beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;

	•	bankruptcy or insolvency events involving us or our subsidiaries;

	•	our inability to demonstrate compliance with financial covenants within a specified period after Bighorn or Fort Union is prohibited from making a distribution to its members;

	•	the entry of, and failure to pay, one or more adverse judgments in excess of $5 million upon which enforcement proceedings are brought or are not stayed pending appeal; and

	•	a change of control (as defined in the revolving credit facility).

If we failed to comply with the financial or other covenants under our revolving credit facility or experienced a material adverse effect on our operations, business, properties, liabilities or financial or other condition, we would

be unable to borrow under our revolving credit facility, and could be in default after specified notice and cure periods. If an event of default exists under the revolving credit facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the revolving credit facility.

Senior Notes. At December 31, 2010, we had $332.7 million in principal amount of our 8.125% senior unsecured notes due 2016 (“2016 Notes”) outstanding, and $249.5 million in principal amount of our 7.75% senior unsecured notes due 2018 (“2018 Notes”) outstanding. We refer to the 2016 Notes and the 2018 Notes collectively as the “Senior Notes.”

Interest and other financing costs relating to the 2016 Notes totaled $27.8 million, $27.8 million and $29.5 million for 2010, 2009 and 2008, respectively. Interest on the 2016 Notes is payable each March 1 and September 1. Interest and other financing costs relating to the 2018 Notes, which we issued in May 2008, totaled $19.9 million, $20.4 million and $15.4 million for 2010, 2009 and 2008, respectively. Interest on the 2018 Notes is payable each June 1 and December 1.

The Senior Notes are jointly and severally guaranteed by all of our wholly owned subsidiaries (other than Copano Energy Finance Corporation, the co-issuer of the Senior Notes). The subsidiary guarantees rank equally in right of payment with all of our guarantor subsidiaries’ existing and future senior indebtedness, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all of our guarantor subsidiaries’ existing and future secured indebtedness (including under our revolving credit facility) to the extent of the value of the assets securing that indebtedness, and all liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries).

The Senior Notes are redeemable, in whole or in part and at our option, at stated redemption prices plus accrued and unpaid interest to the redemption date. If we undergo a change in control, we must give the holders of Senior Notes an opportunity to sell us their notes at 101% of the face amount, plus accrued and unpaid interest to date.

The indentures governing the Senior Notes include customary covenants that limit our and our subsidiary guarantors’ abilities to, among other things:


	•	sell assets;

	•	redeem or repurchase equity or subordinated debt;

	•	make investments;

	•	incur or guarantee additional indebtedness or issue preferred units;

	•	create or incur liens;

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

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

	•	engage in transactions with affiliates;

	•	create unrestricted subsidiaries; and

	•	enter into sale and leaseback transactions.

In addition, the indentures governing our senior unsecured notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the senior unsecured notes indentures) is at least 1.75x. At December 31, 2010, our ratio of EBITDA to fixed charges was 3.5x.

Impact of Inflation

The midstream natural gas industry experienced increasing costs of chemicals, utilities, materials and supplies, labor and equipment in recent years, due in part to increased activity in the energy sector and high commodity

prices. After commodity prices declined sharply in late 2008, operating costs began a correction, and by the end of 2009, these costs had stabilized. Although the impact of inflation has not been material in recent years, it remains a factor in the midstream natural gas industry and in the United States economy in general. To the extent permitted by competition, regulation and our existing agreements, we may pass along increased costs to our customers in the form of higher fees.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2010 and 2009.

Recent Accounting Pronouncements

Fair Value Measurements

In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”), which updates ASC 820-10 to require new disclosure of amounts transferred in and out of Level 1 and Level 2 of the fair value hierarchy and presentation of a reconciliation of changes in fair value amounts in the Level 3 fair value hierarchy on a gross basis rather than a net basis. Additionally, ASU 2010-06 requires greater disaggregation of the assets and liabilities for which fair value measurements are presented and requires expanded disclosure of the valuation techniques and inputs used for Level 2 and Level 3 fair value measurements. We are currently evaluating the impact that ASU 2010-06 may have on our fair value measurement disclosures, but the new guidance will not impact our financial condition or results of operations.

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, please read Notes 2 and 3 to our consolidated financial statements included in Item 8 in this report.

Investments in Unconsolidated Affiliates

We own a 62.5% equity investment in Webb Duval, a Texas general partnership, a majority interest in Southern Dome, a Delaware limited liability company, a 51% equity investment in Bighorn, a Delaware limited liability company, a 37.04% equity investment in Fort Union, a Delaware limited liability company, a 50% equity investment in Eagle Ford Gathering, a Delaware limited liability company and, as of January 18, 2011, a 50% equity investment in Liberty Pipeline Group, a Delaware limited liability company. Although we are the managing partner or member in each of these equity investments and own a majority interest in some of these equity investments, we account for these investments using the equity method of accounting because the remaining general partners or members have substantive participating rights with respect to the management of each of these equity investments. Equity in earnings from our unconsolidated affiliates is included in income from operations as the operations of each of our unconsolidated affiliates are integral to our operations.

We evaluate the carrying value of our investments in unconsolidated subsidiaries when indicators of impairment are present. The impairment test for our investments in unconsolidated affiliates requires that we consider whether the fair value of our equity investment as a whole, not the underlying net assets, has declined, and if so, whether that decline is other than temporary. During the three months ended June 30, 2010, we recorded a $25 million non-cash impairment charge relating to our investment in Bighorn primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the CIG forward price curve. We developed the fair value of our investment in Bighorn (see Note 10) using a probability weighted discounted cash flow model using a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures.

We periodically reevaluate our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with ASC 323 “Investments — Equity Method and Joint Ventures.” As of December 31, 2010, based on favorable forecasted pricing in the region, we believe it is probable that producers on our dedicated acreage will increase drilling and production in the future, and that we will recover our investments in Bighorn and Fort Union. If the assumptions underlying our expectations prove incorrect and volumes do not recover either due to a lack of increased drilling activity or a weak pricing environment, we ultimately would be required to record an impairment of our interests in Bighorn, Fort Union, or both.

Impairment of Long-Lived Assets

In accordance with ASC 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset, including future commodity prices and estimated future natural gas production in the region (which is dependent in part on commodity prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:


	•	changes in general economic conditions in which our assets are located;

	•	the availability and prices of natural gas supply;

	•	improvements in exploration and production technology;

	•	the finding and development cost for producers to exploit reserves in a particular area;

	•	our ability to negotiate favorable agreements with producers and customers;

	•	our dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

	•	competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. An estimate of the sensitivity of these assumptions to our estimated future undiscounted cash flows used in our impairment review is not practicable given the extensive array of our assets and the number of assumptions involved in these estimates. However, based on current period assumptions, a decrease in our estimated future undiscounted cash flows associated with certain assets of 10% could result in a potential impairment of these assets.

Revenue Recognition

Using the revenue recognition criteria of evidence of an arrangement, delivery of a product and the determination of price, our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our service-related revenue is recognized in the period when the service is provided and includes our fee-based service revenue for services such as transportation, compression and processing, including processing under tolling

arrangements. In addition, collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position and their ability to pay.

Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements that establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location on the same or on another specified date. All transactions require physical delivery of the natural gas, and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

On occasion, we enter into buy/sell arrangements that are accounted for on a net basis in the statements of operations as either a net natural gas sale or a net cost of natural gas, as appropriate. These purchase and sale transactions are generally detailed either jointly, in a single contract or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single or multiple counterparties.

Our most common contractual arrangements for gathering, transporting, processing and fractionation services are summarized in the “— Our Contracts” section above. In our Oklahoma and Texas segments, we often provide services under contracts that reflect a combination of contract pricing terms, while substantially all of our Rocky Mountains segment’s contracts are fee-based arrangements. In addition to providing for compensation for our gathering, transportation, processing or fractionation services, in many cases, our contracts also allow us to charge producers fees for treating, compression, dehydration or other services. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter in the form of “processing upgrade” payments during periods where such margins are in excess of an agreed-upon amount. See “— Our Contracts” for additional information on our contractual arrangements.

Risk Management Activities

ASC 815 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. In accordance with ASC 815, we recognize all derivatives as either risk management assets or liabilities in our consolidated balance sheets and measure those instruments at fair value. If the financial instruments meet the hedging criteria, changes in fair value will be recognized in earnings for fair value hedges and in other comprehensive income for the effective portion of cash flow hedges. Ineffectiveness in cash flow hedges is recognized in earnings in the period in which the ineffectiveness occurs. Gains and losses on cash flow hedges are reclassified to operating revenue as the forecasted transactions impact earnings. We included changes in our risk management activities in cash flow from operating activities on the consolidated statements of cash flows.

We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the risks to our cash flow and profitability resulting from changes in commodity prices and interest rates. We recognize these transactions as assets and liabilities on our consolidated balance sheets based on the instrument’s fair value. We estimate the fair value of our financial derivatives using valuation models based on whether the inputs to those valuation techniques are observable or unobservable. For further details on our risk management activities, please read Note 9, “Financial Instruments,” to our consolidated financial statements.


Item 7A.	*Quantitative and Qualitative Disclosures about Market Risk.*

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

Commodity Price Risk

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing or conditioning at our processing plants or third-party processing plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) the cost of transporting and fractionating NGLs. The following discussion describes our commodity price risks as of December 31, 2010. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly.

Texas. Our Texas pipeline systems purchase natural gas for transportation and resale and also transport and provide other services on a fee-for-service basis. Many of the contracts we executed in 2010 have been fee-based and have provided for volume commitments by producers, under which the producer is obligated to deliver an agreed volume of natural gas and to pay a “deficiency fee” to the extent the producer delivers less than the agreed volume. However, a significant portion of the margins we realize from purchasing and reselling the natural gas under older contracts is based on a percentage of a stated index price. Accordingly, these margins decrease in periods of low natural gas prices and increase during periods of high natural gas prices. The fees we charge to transport natural gas for the accounts of others are primarily fixed, but our Texas contracts also include a percentage-of-index component in a number of cases.

While we have increasingly focused on obtaining fee-based arrangements, a significant portion of the gas processed by the Texas segment through our Houston Central complex is still processed under keep-whole with fee arrangements. Under these arrangements, increases in NGL prices or decreases in natural gas prices generally have a positive impact on our processing gross margins and, conversely, a reduction in NGL prices or increases in natural gas prices generally negatively impact our processing gross margins.

Oklahoma. A majority of the processing contracts in our Oklahoma segment are percentage-of-proceeds arrangements. Under these arrangements, we purchase and process natural gas from producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase and revenues and gross margins decrease as natural gas and NGL prices decrease. Our Oklahoma segment also has fixed-fee contracts and percentage-of-index contracts.

Rocky Mountains. Substantially all of our Rocky Mountains contractual arrangements as well as the contractual arrangements of Fort Union and Bighorn are fixed-fee arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. The cash flow from these arrangements is directly related to natural gas volumes and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, our cash flow would also decline.

Other Commodity Price Risks. Although we seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations, we experience imbalances between our natural gas purchases and sales from time to time. For example, a producer could fail to deliver or deliver in excess of contracted volumes, or a customer could take more or less than contracted volumes. To the extent our purchases and sales of natural gas are not balanced, we face increased exposure to commodity prices with respect to the imbalance.

We purchase and sell natural gas under a variety of pricing arrangements, for example, by reference to first of the month index prices, daily index prices or a weighted average of index prices over a given period. Our goal is to minimize commodity price risk by aligning the combination of pricing methods and indices under which we purchase natural gas in each of our segments with the combination under which we sell natural gas in these segments, although it is not always possible to do so.

Basis risk is the risk that the value of a hedge may not move in tandem with the value of the actual price exposure that is being hedged. Any disparity in terms, such as product, time or location, between the hedge and the underlying exposure creates the potential for basis risk. Our long position in natural gas in Oklahoma can serve as a hedge against our short position in natural gas in Texas. To the extent we rely on natural gas from our Oklahoma segment, which is priced primarily on the CenterPoint East index, to offset a short position in natural gas in our Texas segment, which is priced on the Houston Ship Channel index, we are subject to basis risk. In addition, we are subject to basis risk to the extent we hedge Oklahoma NGL volumes because, due to the limited liquidity in the forward market for Conway-based hedge instruments, we use Mt. Belvieu-priced hedge instruments for our Oklahoma NGL volumes. The CenterPoint East and Houston Ship Channel indices and the Mt. Belvieu and Conway indices historically have been highly correlated; however, these indices displayed greater variability beginning in late 2008 and for much of 2009 before returning to a correlation more consistent with their historical pattern in late 2009 and throughout 2010.

To mitigate basis risk affecting our natural gas positions in Oklahoma and Texas, we have basis swaps on the CenterPoint East and the Houston Ship Channel indices for 2010 and 2011. Also, in November 2010, we amended our risk management policy to permit purchase of basis swaps on NGLs, priced at Mt. Belvieu or Conway, to allow us to lock in basis spread price differentials between Mt. Belvieu and Conway and eliminate the risk of the basis fluctuation. For additional information about our commodity hedge portfolio at December 31, 2010, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of this report.

Sensitivity. In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $0.8 million to our total segment gross margin for the year ended December 31, 2010. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in a corresponding decrease of approximately $0.1 million to our total segment gross margin, and vice versa, for the year ended December 31, 2010. These relationships are not necessarily linear. As actual prices have fallen below the strike prices of our hedges in 2010, sensitivity to further changes in commodity prices have been reduced. Also, if processing margins are negative, we can operate our Houston Central complex in a conditioning mode so that additional increases in natural gas prices would have a positive impact on our total segment gross margin.

Risk Management Oversight

We seek to mitigate the price risk of natural gas and NGLs, and our interest rate risk discussed below under “— Interest Rate Risk”, through the use of derivative instruments. These activities are governed by our risk management policy. Our Risk Management Committee is responsible for our compliance with our risk management policy and consists of our Chief Executive Officer, Chief Financial Officer, General Counsel and the President of any operating segment. The Audit Committee of our Board of Directors monitors the implementation of our risk management policy, and we have engaged an independent firm to monitor compliance with our risk management policy on a monthly basis.

Our risk management policy provides that derivative transactions must be executed by our Chief Financial Officer or his designee and must be authorized in advance of execution by our Chief Executive Officer.

As of December 31, 2010, we were in compliance with our risk management policy.

Commodity Price Hedging Activities

Permitted Derivative Instruments. Our risk management policy allows our management to:


	•	purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on WTI crude oil to hedge NGLs produced or condensate collected by us or an entity or asset to be acquired by us if a binding purchase and sale agreement has been executed (a “Pending Acquisition”);

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

	•	purchase put options, enter into collars or “put spreads” (purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps or floating-for-floating swaps (basis swaps) on NGLs to which we or a Pending Acquisition has direct price exposure, priced at Mt. Belvieu or Conway; and

	•	purchase put options and collars and/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for any processing plant relevant to our operations or a Pending Acquisition.

Limitations. Our policy also limits the maturity and notional amounts of our derivatives transactions as follows:


	•	Maturities with respect to the purchase of any crude oil, natural gas, NGLs, fractionation spread or processing margin spread hedge instruments must be limited to five years from the date of the transaction;

	•	Except as provided below under “Exception to Volume Limitations,” we may not (i) purchase crude oil or NGLs put options, (ii) purchase natural gas put or call options, (iii) purchase fractionation spread or processing margin spread put options or (iv) enter into any crude oil, natural gas or NGLs spread options permitted by the policy if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged commodity would exceed 80% of the projected requirements or output, as applicable, for the hedged period. We are required to divest outstanding hedge positions only to the extent net notional hedged volumes with respect to an underlying hedged commodity exceed 100% of the projected requirements or output, as applicable, for the hedged period;

	•	The aggregate volumetric exposure associated with swaps (other than basis swaps), collars and written calls relating to any product must not exceed the lesser of 50% of the aggregate hedged position or 35% of the projected requirements or output with respect to such product; and

	•	We may not enter into a basis swap if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged basis would exceed 80% of the projected requirements or output, as applicable, for the hedged period. We are required to divest outstanding basis swaps only to the extent net notional hedged volumes with respect to an underlying hedged basis exceed 100% of the projected requirements or output, as applicable, for the hedged period.

Our policy of limiting swaps (other than basis swaps) relating to any product to the lesser of a percentage of our overall hedge position or a percentage of the related projected requirements or output is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.

Exception to Volume Limitations. The volume limitations under our risk management policy provide that the notional amounts of put options with strike prices that are greater than 33% out-of-the-money (market price exceeds strike price by greater than 33%) may be excluded from the notional volume limitations for so long as such put options remain out-of-the-money. In the event that the strike price of such a put option returns to being in-the-money, the instrument’s notional amount would again be included in the volume limitations. If the reversal of a prior exclusion results in an over-hedged notional position, we will be required to become compliant with the notional volume limitations within 30 days of the reversal.

Approved Markets. Our risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (“NYMEX”) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. All of our hedge counterparties are also lenders under our senior credit facility, and the payment obligations in connection with our hedge transactions are secured by a first priority lien on the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. We have not executed any derivative transactions on the NYMEX as of December 31, 2010.

We will seek, whenever possible, to enter into hedge transactions that meet the requirements for effective hedges as outlined in ASC 815.

Texas Segment. With the exception of condensate and a portion of our natural gasoline production, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. We use natural gas calls and call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central complex. The calls and call spread options are based on the Houston Ship Channel index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas segment because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central complex to switch between full recovery and conditioning mode.

Oklahoma Segment. Historically, we have used options priced on the CenterPoint East index to hedge natural gas in Oklahoma. For 2010, we used a basis swap between the CenterPoint East and the Houston Ship Channel indices to mitigate the basis risk affecting Oklahoma natural gas that we use to offset our short natural gas position in Texas. Currently, the principal indices used to price the underlying commodity for our Oklahoma segment are the ONEOK Gas Transportation index and the CenterPoint East index. While this creates the potential for additional basis risk, statistical analysis reveals that the CenterPoint East index and the ONEOK Gas Transportation index historically have been highly correlated. With the exception of condensate, NGLs are contractually priced using the Conway index, but because there is an extremely limited forward market for Conway-based hedge instruments, we use the Mt. Belvieu index for NGL hedges. This creates the potential for basis risk. Historically these indices have been highly correlated; however, these indices displayed greater variability beginning in late 2008 and for much of 2009 before returning to a correlation more consistent with their historical pattern in late 2009 and throughout 2010. In the second quarter of 2010, the basis between the Conway index and the Mt. Belvieu index widened to a maximum quarterly average differential of $5.89 per barrel and during the first quarter of 2010, the basis differential retracted to a quarterly average low of $2.94 per barrel. At February 17, 2011 this basis differential was $6.76 per barrel.

Rocky Mountains Segment. Because the profitability of our Rocky Mountains segment is only indirectly affected by the level of commodity prices, this segment has no outstanding transactions to hedge commodity price risk.

Our Hedge Portfolio

Commodity Hedges. As of December 31, 2010, our commodity hedge portfolio totaled $14.9 million, which consists of assets aggregating $19.8 million less liabilities aggregating $4.9 million. For additional information, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of this report.

Houston Ship Channel Index Purchased Natural Gas Options


	Call Spread						Call
	Call Strike				Call Volumes		Strike		Volume
	(Per MMBtu)				(MMBtu/d)		(Per MMBtu)		(MMBtu/d)
	Bought		Sold

2011	$	6.9500	$	10.0000		7,100	$	10.0000		10,000

Mt. Belvieu Purity Ethane Purchased Puts and Entered into Swaps


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

2011	$	0.5300		2,200	$	0.5450		500
2011	$	0.6200		500	$	—		—
2011	$	0.5500		500	$	—		—
2012	$	0.5900		1,000	$	—		—

Mt. Belvieu TET Propane Purchased Puts and Entered into Swaps


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

2011⁽²⁾	$	0.8265		1,100	$	—		—
2011	$	0.9340		700	$	0.9750		700
2011	$	1.3300		900	$	—		—
2012	$	1.1500		700	$	—		—
2012	$	1.0700		600	$	—		—
2012⁽¹⁾	$	1.1700		600	$	—		—


(1)		Instrument purchased in February 2011.

(2)		Instrument is not designated as a cash flow hedge under hedge accounting as of January 2011.

Mt. Belvieu Non-TET Isobutane Purchased Puts and Entered into Swaps


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

2011⁽²⁾	$	1.0205		300	$	—		—
2011	$	1.1100		100	$	1.1800		100
2011	$	1.3900		160	$	—		—
2011	$	1.7100		200	$	—		—
2012	$	1.3900		450	$	—		—
2013⁽¹⁾	$	1.6000		200	$	—		—


(1)		Instrument purchased in February 2011.

(2)		Instrument is not designated as a cash flow hedge under hedge accounting as of August 2010.

Mt. Belvieu Non-TET Normal Butane Purchased Puts and Entered into Swaps


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

2011⁽²⁾	$	1.0205		300	$	—		—
2011	$	1.0850		200	$	1.1700		200
2011	$	1.3500		140	$	—		—
2011	$	1.7100		350	$	—		—
2012	$	1.3500		250	$	—		—
2012	$	1.3600		350	$	—		—
2012	$	1.4600		150	$	—		—
2013⁽¹⁾	$	1.5800		300	$	—		—


(1)		Instrument purchased in February 2011.

(2)		Instrument is not designated as a cash flow hedge under hedge accounting as of August 2010.

Mt. Belvieu Non-TET Purchased Natural Gasoline Puts


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

2011	$	1.4100		300

Natural Gas Basis Swaps

Purchased Houston Ship

Channel Index

Sold CenterPoint East Index

Price

Volume

Price

Volume

(Per MMBtu)

(MMBtu/d)

(Per MMBtu)

(MMBtu/d)

2011⁽³⁾

0.1050

10,000

—

0.3050

10,000


(3)		Instrument is not designated as a cash flow hedge under hedge accounting.

WTI Crude Oil Purchased Puts


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

2011⁽²⁾	$	55.00		1,000
2011	$	60.00		400
2011	$	77.00		700
2011	$	79.00		400
2011	$	85.00		200
2012	$	79.00		300
2012	$	83.00		650
2012	$	85.00		350
2012	$	90.00		200
2013	$	90.00		400
2013⁽¹⁾	$	99.00		350


(1)		Instrument purchased in February 2011.

(2)		Instrument is not designated as a cash flow hedge under hedge accounting as of September 2009.

Interest Rate Swaps. As of December 31, 2010, the fair value of our interest rate swaps liability totaled $7.0 million. For additional information on our interest rate swaps, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of the report.

Counterparty Risk

We are diligent in attempting to ensure that we provide credit only to credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the year ended December 31, 2010, DCP Midstream (12%), ONEOK Energy Services, L.P. (16%), ONEOK Hydrocarbons, L.P. (20%), Dow Hydrocarbons and Resources, L.L.C. (9%), Kinder Morgan (7%) and Enterprise Products Operating, L.P. (9%), collectively, accounted for approximately 73% of our revenue. As of December 31, 2010, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services. Companies accounting for another approximately 19% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of December 31, 2010, JP Morgan Chase Bank N.A. (35%), Barclays Bank PLC (27%), Bank of Nova Scotia (23%) and Credit Suisse USA, Inc (7%) accounted for approximately 92% of the value of our net commodity hedging positions. As of December 31, 2010, all of our counterparties were rated A2 and A- or better by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively. Our hedge counterparties have not posted collateral to secure their obligations to us.

We have historically experienced minimal collection issues with our counterparties; however, nonpayment or nonperformance by one or more significant counterparties could adversely impact our liquidity. Please read Item 1A, “Risk Factors.”


Item 8.	*Financial Statements and Supplementary Data*

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements
and supplementary financial data required for this Item are set forth on pages F-1 through F-[-] of
this report and are incorporated herein by reference.


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

None.


Item 9A.	*Controls and Procedures*

Management’s Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Management’s Annual Report on Internal Control over Financial Reporting

Our management, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in

Rules 13a-15(f) of the Exchange Act. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)) as of the end of the period covered by this report. We based our evaluation on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in the publication entitled, “Internal Control — Integrated Framework” (the “COSO Framework”).

Based on our evaluation and the COSO Framework, we believe that, as of December 31, 2010, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Deloitte & Touche LLP, our independent registered public accounting firm, has issued a report on our internal control over financial reporting, which is included in “Report of Independent Registered Public Accounting Firm” below.

Changes in Internal Controls Over Financial Reporting

Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at December 31, 2010 at the reasonable assurance level. There has been no change in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2010 that has materially affected or is reasonably likely to materially affect such internal controls over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
AS OF DECEMBER 31, 2010

The management of Copano Energy, L.L.C. and its consolidated subsidiaries, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) as of the end of the period covered by this report. The Company based its evaluation on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in the publication entitled, “Internal Control — Integrated Framework” (the “COSO Framework”). Our assessment of internal controls over financial reporting included design effectiveness and operating effectiveness of internal control over financial reporting, as well as the safeguarding of our assets.

Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. A system of internal control may become inadequate over time because of changes in conditions or deterioration in the degree of compliance with the policies or procedures. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we believe that, as of December 31, 2010, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO Framework.

Deloitte and Touche LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this annual report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 25, 2011.


/s/ R. Bruce Northcutt R. Bruce Northcutt President and Chief Executive Officer		/s/ Carl A. Luna Carl A. Luna Senior Vice President and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Copano Energy, L.L.C. and Subsidiaries:

Houston, Texas

We have audited the internal control over financial reporting of Copano Energy, L.L.C. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010 of the Company and our report dated February 25, 2011 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Houston, Texas

February 25, 2011

PART III


Item 9B.	*Other Information*

None.


Item 10.	*Directors, Executive Officers and Corporate Governance*

The information required by Item 10 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2011 Annual Meeting of Unitholders set forth under the caption “Proposal One — Election of Directors,” “The Board of Directors and its Committees” and “Executive Officers.”


Item 11.	*Executive Compensation*

The information required by Item 11 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2011 Annual Meeting of Unitholders set forth under the captions “The Board of Directors and its Committees — Director Compensation,” “The Board of Directors and its Committees — Compensation Committee Interlocks and Insider Participation,” “Compensation Disclosure and Analysis,” “Executive Compensation,” “Report of the Compensation Committee” and “Section 16(a) Beneficial Ownership Reporting Compliance.”


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters*

The information required by Item 12, including information concerning securities authorized for issuance under our equity compensation plan for directors and employees, is incorporated herein by reference to our Proxy Statement for our 2011 Annual Meeting of Unitholders set forth under the captions “Securities Authorized for Issuance under Equity Compensation Plans,” “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation.”


Item 13.	*Certain Relationships and Related Transactions, and Director Independence*

The information required by Item 13 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2011 Annual Meeting of Unitholders set forth under the caption “Certain Relationships and Related Transactions, and Director Independence” to be filed with the SEC not later than 120 days after the close of the fiscal year.


Item 14.	*Principal Accounting Fees and Services*

The information required by Item 14 is incorporated herein by reference to the applicable information in our Proxy Statement for our 2011 Annual Meeting of Unitholders set forth under the caption “Proposal Two — Ratification of Independent Registered Public Accounting Firm.”

PART IV


Item 15.	*Exhibits and Financial Statement Schedules*

(a)(1) and (2) Financial Statements

The consolidated financial statements of Copano Energy, L.L.C are listed on the Index to Financial Statements to this report beginning on page F-1.

(a)(3) Exhibits

The following documents are filed as a part of this report or incorporated by reference.


Number			Description

	3	.1	Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.2	Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.3	Fourth Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed July 21, 2010).
	3	.4	Amendment No. 1 to Fourth Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed July 22, 2010).
	4	.1	Indenture dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
	4	.2	Form of Global Note representing 8.125% Senior Notes due 2016 (included in 144A/Regulation S Appendix to Exhibit 4.1 above).
	4	.3	Indenture, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 19, 2008).
	4	.4	Form of Global Note representing 7.75% Senior Notes due 2018 (included in 144A/Regulation S Appendix to Exhibit 4.3 above).
	4	.5	Series A Convertible Preferred Unit Purchase Agreement, dated July 21, 2010, by and between Copano Energy, L.L.C. and TPG Copenhagen, L.P. (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed July 22, 2010).
	4	.6	Registration Rights Agreement, dated July 21, 2010, by and between Copano Energy, L.L.C. and TPG Copenhagen, L.P. (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed July 22, 2010).
	4	.7	Director Designation Agreement, dated July 21, 2010, by and between Copano Energy, L.L.C. and TPG Copenhagen, L.P. (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed July 22, 2010).
	10	.1	Amended and Restated Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed February 24, 2009).
	10	.2	Amendment to Amended and Restated Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed May 18, 2009).
	10	.3	Administrative and Operating Services Agreement effective January 1, 2010, among Copano/Operations, Inc. and CPNO Services, L.P. (incorporated by reference to Exhibit 10.3 to Annual Report on Form 10-K filed March 1, 2010).
	10	.4*	Amendment No. 1 to Administrative and Operating Services Agreement effective January 1, 2010, among Copano/Operations, Inc. and CPNO Services, L.P.


Number			Description

	10	.5	Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated April 9, 2003 (incorporated by reference to Exhibit 10.8 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
	10	.6	First Amendment to Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated July 30, 2004 (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
	10	.7	Assignment and Assumption Agreement between Copano/Operations, Inc. and CPNO Services, L.P. effective January 1, 2005 with respect to Employment Agreement between Copano/Operations, Inc., R Bruce Northcutt and the Copano Controlling Entities, as amended (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
	10	.8	Second Amendment to Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the Copano Controlling Entities, effective March 1, 2005 (incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K filed March 31, 2005).
	10	.9	Third Amendment to Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the Copano Controlling Entities, effective November 18, 2008 (incorporated by reference to Exhibit 99.2 to Annual Report on Form 10-K filed November 25, 2008).
	10	.10	Retirement, Release and Consulting Services Agreement between Copano Energy, L.L.C. and John A. Raber, effective as of August 2, 2010 (incorporated by reference to Exhibit 99.1 to Form 8-K filed July 30, 2010).
	10	.11	Employment Agreement between ScissorTail Energy, L.L.C. and Sharon Robinson dated as of August 1, 2005 (incorporated by reference to Exhibit 10.34 to Quarterly Report on Form 10-Q filed August 15, 2005).
	10	.12	First Amendment to Employment Agreement between ScissorTail Energy, L.L.C. and Sharon Robinson dated as of December 31, 2008 incorporated by reference to Exhibit 10.15 to Annual Report on Form 10-K filed February 27, 2009).
	10	.13	2004 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed December 15, 2004).
	10	.14	2004 Form of Unit Option Grant (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q filed December 21, 2004).
	10	.15	2005 Form of Restricted Unit Grant (Employees) (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-8 filed February 11, 2005).
	10	.16	2005 Form of Unit Option Grant (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8 filed February 11, 2005).
	10	.17	Form of Unit Option Grant (ScissorTail Energy, LLC Officers) (incorporated by reference to Exhibit 10.37 to Quarterly Report on Form 10-Q filed August 15, 2005).
	10	.18	Form of Restricted Unit Grant (ScissorTail Energy, LLC Officers) (incorporated by reference to Exhibit 10.38 to Quarterly Report on Form 10-Q filed August 15, 2005).
	10	.19	2006 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed May 30, 2006).
	10	.20	2006 Form of Unit Option Grant (Employees) (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed May 30, 2006).
	10	.21	2006 Form of Restricted Unit Grant (Employees) (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K filed May 30, 2006).
	10	.22	November 2006 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed November 20, 2006).
	10	.23	2007 Form of Phantom Unit Grant (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed June 18, 2007).
	10	.24	2008 Form of Phantom Unit Grant (Employees) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed June 6, 2008).
	10	.25	2008 Form of Performance Based Phantom Unit Grant (Employees) (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed June 6, 2008).


Number			Description

	10	.26	2008 Form of Long-Term Retention Award Grant (Employees) (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed June 6, 2008).
	10	.27	2008 Form of Phantom Unit Grant (Employee Bonus Awards) (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed November 12, 2008).
	10	.28	2008 Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 99.4 to Current Report on Form 8-K filed November 25 2008).
	10	.29	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed May 18, 2009).
	10	.30	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed August 18, 2009).
	10	.31	Form of Performance-Based Phantom Unit Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed June 10, 2010).
	10	.32	Form of Restricted Unit Award Agreement (Director Pursuant to Contract) (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed November 23, 2010).
	10	.33	Amended and Restated Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed February 23, 2010).
	10	.34	2010 Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed February 23, 2010).
	10	.35	Copano Energy, L.L.C. Deferred Compensation Plan dated December 16, 2008 (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed December 19, 2008).
	10	.36	Form of Deferred Compensation Plan Participation Agreement (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed December 19, 2008).
	10	.37	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed November 2, 2005).
	10	.38	Copano Energy, L.L.C. Amended and Restated Change in Control Severance Plan effective August 25, 2010 (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed August 31, 2010).
	10	.39	Lease Agreement dated as of October 17, 2000, between Plow Realty Company of Texas and Texas Gas Plants, L.P. (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
	10	.40	Lease Agreement dated as of December 3, 1964, between The Plow Realty Company of Texas and Shell Oil Company (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
	10	.41	Lease Agreement dated as of January 1, 1944, between The Plow Realty Company of Texas and Shell Oil Company, Incorporated (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
	10	.42†	Amended and Restated Gas Processing Contract, effective as of June 1, 2010, between Copano Processing, L.P. and Kinder Morgan Texas Pipeline, L.P. (incorporated by reference to Exhibit 10.1 to Quarterly Report on Form 10-Q filed August 6, 2010).
	10	.43	Amended and Restated Credit Agreement dated as of January 12, 2007, among Copano Energy, L.L.C., as the Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association, as Co-Syndication Agents and The Other Lenders Party thereto and Banc of America Securities LLC, as Sole Lead Arranger and Sole Book Manager (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed January 19, 2007).
	10	.44	First Amendment to Amended and Restated Credit Agreement, dated October 19, 2007 (incorporated by reference to Exhibit 10.40 to Annual Report on Form 10-K filed February 29, 2008).
	10	.45	Second Amendment to the Amended and Restated Credit Agreement, dated July 21, 2010 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed July 22, 2010).

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 25th day of February 2011.

COPANO ENERGY, L.L.C.


	By:	/s/ R. Bruce Northcutt

R. Bruce Northcutt

President and Chief Executive Officer

(Principal Executive Officer)


	By:	/s/ Carl A. Luna

Carl A. Luna

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Pursuant to the requirements of the Exchange Act, this Annual Report has been signed below on the dates indicated by the following persons on behalf of the Registrant and in the capacities indicated.


Signature	Title	Date


/s/ R. Bruce Northcutt R. Bruce Northcutt	President and Chief Executive Officer and Director (Principal Executive Officer)	February 25, 2011

/s/ Carl A. Luna Carl A. Luna	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 25, 2011

/s/ Lari Paradee Lari Paradee	Senior Vice President, Controller and Principal Accounting Officer (Principal Accounting Officer)	February 25, 2011

/s/ William L. Thacker William L. Thacker	Chairman of the Board of Directors	February 25, 2011

/s/ James G. Crump James G. Crump	Director	February 25, 2011

/s/ Ernie L. Danner Ernie L. Danner	Director	February 25, 2011

/s/ Scott A. Griffiths Scott A. Griffiths	Director	February 25, 2011

/s/ Michael L. Johnson Michael L. Johnson	Director	February 25, 2011

/s/ T. William Porter T. William Porter	Director	February 25, 2011

/s/ Michael G. MacDougall Michael G. MacDougall	Director	February 25, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of Copano Energy, L.L.C. and Subsidiaries:

Houston, Texas

We have audited the accompanying consolidated balance sheets of Copano Energy, L.L.C. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, members’ capital and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Copano Energy, L.L.C. and subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Houston, Texas

February 25, 2011

F-2

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(In thousands,
	except unit information)

ASSETS
Current assets:
Cash and cash equivalents	$	59,930		$	44,692
Accounts receivable, net		96,662			91,156
Risk management assets		7,836			36,615
Prepayments and other current assets		5,179			4,937

Total current assets		169,607			177,400

Property, plant and equipment, net		912,157			841,323
Intangible assets, net		188,585			190,376
Investments in unconsolidated affiliates		604,304			618,503
Escrow cash		1,856			1,858
Risk management assets		11,943			15,381
Other assets, net		18,541			22,571

Total assets	$	1,906,993		$	1,867,412


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	117,706		$	111,021
Accrued interest		10,621			11,921
Accrued tax liability		913			672
Risk management liabilities		9,357			9,671
Other current liabilities		14,495			9,358

Total current liabilities		153,092			142,643

Long term debt (includes $546 and $628 bond premium as of December 31, 2010 and 2009, respectively)		592,736			852,818
Deferred tax provision		1,883			1,862
Risk management and other noncurrent liabilities		4,525			10,063
Commitments and contingencies (Note 11)
Members’ capital:
Series A convertible preferred units, no par value, 10,585,197 units and 0 units issued and outstanding as of December 31, 2010 and 2009, respectively		285,172			—
Common units, no par value, 65,915,173 units and 54,670,029 units issued and outstanding as of December 31, 2010 and 2009, respectively		1,161,652			879,504
Class D units, no par value, 0 and 3,245,817 units issued and outstanding as of December 31, 2010 and 2009, respectively		—			112,454
Paid in capital		51,743			42,518
Accumulated deficit		(313,454	)		(158,267	)
Accumulated other comprehensive loss		(30,356	)		(16,183	)

		1,154,757			860,026

Total liabilities and members’ capital	$	1,906,993		$	1,867,412

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

F-3

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2010			2009			2008
	(In thousands, except per unit information)

Revenue:
Natural gas sales	$	381,453		$	316,686		$	747,258
Natural gas liquids sales		490,980			406,662			597,986
Transportation, compression and processing fees		68,398			55,983			59,006
Condensate and other		54,333			40,715			50,169

Total revenue		995,164			820,046			1,454,419

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		745,074			576,448			1,178,304
Transportation⁽¹⁾		22,701			24,148			21,971
Operations and maintenance		53,487			51,477			53,824
Depreciation, amortization and impairment		62,572			56,975			52,916
General and administrative		40,347			39,511			45,571
Taxes other than income		4,726			3,732			3,019
Equity in loss (earnings) from unconsolidated affiliates		20,480			(4,600	)		(6,889	)

Total costs and expenses		949,387			747,691			1,348,716

Operating income		45,777			72,355			105,703
Other income (expense):
Interest and other income		78			1,202			1,174
Gain on retirement of unsecured debt		—			3,939			15,272
Interest and other financing costs		(53,605	)		(55,836	)		(64,978	)

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

(Loss) income from continuing operations		(8,681	)		20,866			55,922
Discontinued operations, net of tax (Note 13)		—			2,292			2,291

Net (loss) income		(8,681	)		23,158			58,213
Preferred unit distributions		(15,188	)		—			—

Net (loss) income to common units	$	(23,869	)	$	23,158		$	58,213

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

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

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

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

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


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

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

F-4

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2010			2009			2008
	(In thousands)

Cash Flows From Operating Activities:
Net (loss) income	$	(8,681	)	$	23,158		$	58,213
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, amortization and impairment		62,572			57,539			50,314
Impairment of goodwill		—			—			2,840
Amortization of debt issue costs		3,755			3,955			4,467
Equity in loss (earnings) from unconsolidated affiliates		20,480			(4,600	)		(6,889	)
Distributions from unconsolidated affiliates		22,416			20,931			22,460
Gain on retirement of unsecured debt		—			(3,939	)		(15,272	)
Non-cash (gain) loss on risk management activities, net		(984	)		(6,879	)		12,751
Equity-based compensation		9,311			8,455			5,858
Deferred tax provision		21			144			486
Other non-cash items, net		(504	)		(816	)		98
Changes in assets and liabilities:
Accounts receivable		(4,780	)		5,545			32,090
Prepayments and other current assets		(242	)		67			(1,123	)
Risk management activities		13,345			30,155			(27,037	)
Accounts payable		6,626			8,764			(44,766	)
Other current liabilities		263			(1,161	)		(4,566	)

Net cash provided by operating activities		123,598			141,318			89,924

Cash Flows From Investing Activities:
Additions to property, plant and equipment		(117,875	)		(73,232	)		(152,533	)
Additions to intangible assets		(9,828	)		(3,060	)		(9,189	)
Acquisitions		—			(2,840	)		(12,655	)
Investments in unconsolidated affiliates		(33,002	)		(4,228	)		(26,832	)
Distributions from unconsolidated affiliates		3,539			8,753			3,370
Escrow cash		2			—			(1,858	)
Proceeds from sale of assets		447			6,061			28
Other, net		(13	)		(2,421	)		814

Net cash used in investing activities		(156,730	)		(70,967	)		(198,855	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		100,000			70,000			579,000
Repayment of long-term debt		(360,000	)		(20,000	)		(339,000	)
Retirement of unsecured debt (Note 5)		—			(14,286	)		(34,313	)
Deferred financing costs		(995	)		—			(6,688	)
Distributions to unitholders		(145,531	)		(125,721	)		(104,234	)
Proceeds from issuance of Series A convertible preferred units, net of underwriting discounts and commissions of $8,935		291,065			—			—
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223		164,786			—			—
Capital contributions from Pre-IPO Investors (Note 6)		—			—			4,103
Equity offering costs		(6,395	)		—			(47	)
Proceeds from option exercises		5,440			664			1,129

Net cash provided by (used in) financing activities		48,370			(89,343	)		99,950

Net increase (decrease) in cash and cash equivalents		15,238			(18,992	)		(8,981	)
Cash and cash equivalents, beginning of year		44,692			63,684			72,665

Cash and cash equivalents, end of year	$	59,930		$	44,692		$	63,684

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

F-5

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL AND COMPREHENSIVE (LOSS) INCOME


																																		Accumulated
	Series A Preferred					Common					Class C						Class D						Class E											Other						Total
	Number		Preferred			Number		Common			Number			Class C			Number			Class D			Number			Class E			Paid-in		Accumulated			Comprehensive						Comprehensive
	of Units		Units			of Units		Units			of Units			Units			of Units			Units			of Units			Units			Capital		Deficit			(Loss) Income			Total			Income (Loss)
																				(In thousands)

Balance, December 31, 2007		—	$	—			47,366	$	661,585			1,184		$	40,492			3,246		$	112,454			5,599		$	175,634		$	23,773	$	(7,867	)	$	(111,935	)	$	894,136
Capital contributions from Pre-IPO Investors		—		—			—		—			—			—			—			—			—			—			4,103		—			—			4,103		$	—
Conversion of Class C Units into common units		—		—			789		26,995			(789	)		(26,995	)		—			—			—			—			—		—			—			—			—
Conversion of Class E Units into common units		—		—			5,599		175,634			—			—			—			—			(5,599	)		(175,634	)		—		—			—			—			—
Cash distributions to common unitholders		—		—			—		—			—			—			—			—			—			—			—		(105,042	)		—			(105,042	)		—
Equity-based compensation		—		—			211		1,129			—			—			—			—			—			—			5,858		—			—			6,987			—
Net income		—		—			—		—			—			—			—			—			—			—			—		58,213			—			58,213			58,213
Derivative settlements reclassified to income		—		—			—		—			—			—			—			—			—			—			—		—			45,529			45,529			45,529
Unrealized gain-change in fair value of derivatives		—		—			—		—			—			—			—			—			—			—			—		—			134,032			134,032			134,032

Comprehensive loss																																								$	237,774

Balance, December 31, 2008		—		—			53,965		865,343			395			13,497			3,246			112,454			—			—			33,734		(54,696	)		67,626			1,037,958
Conversion of Class C Units into common units		—		—			395		13,497			(395	)		(13,497	)		—			—			—			—			—		—			—			—		$	—
Cash distributions to common unitholders		—		—			—		—			—			—			—			—			—			—			—		(126,729	)		—			(126,729	)		—
Equity-based compensation		—		—			310		664			—			—			—			—			—			—			8,784		—			—			9,448			—
Net income		—		—			—		—			—			—			—			—			—			—			—		23,158			—			23,158			23,158
Derivative settlements reclassified to income		—		—			—		—			—			—			—			—			—			—			—		—			(42,200	)		(42,200	)		(42,200	)
Unrealized loss-change in fair value of derivatives		—		—			—		—			—			—			—			—			—			—			—		—			(41,609	)		(41,609	)		(41,609	)

Comprehensive loss																																								$	(60,651	)

Balance, December 31, 2009		—		—			54,670		879,504			—			—			3,246			112,454			—			—			42,518		(158,267	)		(16,183	)		860,026
Conversion of Class D Units into common units		—		—			3,246		112,454			—			—			(3,246	)		(112,454	)		—			—			—		—			—			—		$	—
Issuance of preferred units (paid-in-kind)		258		7,500			—		—			—			—			—			—			—			—			—		—			—			7,500			—
Accrued in-kind units		—		7,688			—		—			—			—			—			—			—			—			—		—			—			7,688			—
In-kind distributions		—		(15,188	)		—		—			—			—			—			—			—			—			—		—			—			(15,188	)		—
Cash distributions to common unitholders		—		—			—		—			—			—			—			—			—			—			—		(146,506	)		—			(146,506	)		—
Issuance of units		10,327		300,000			7,446		172,008			—			—			—			—			—			—			—		—			—			472,008			—
Equity offering costs		—		(14,828	)		—		(7,754	)		—			—			—			—			—			—			—		—			—			(22,582	)		—
Equity-based compensation		—		—			553		5,440			—			—			—			—			—			—			9,225		—			—			14,665			—
Net loss		—		—			—		—			—			—			—			—			—			—			—		(8,681	)		—			(8,681	)		(8,681	)
Derivative settlements reclassified to income		—		—			—		—			—			—			—			—			—			—			—		—			(2,671	)		(2,671	)		(2,671	)
Unrealized loss-change in fair value of derivatives		—		—			—		—			—			—			—			—			—			—			—		—			(11,502	)		(11,502	)		(11,502	)

Comprehensive loss																																								$	(22,854	)

Balance, December 31, 2010		10,585	$	285,172			65,915	$	1,161,652			—		$	—			—		$	—			—		$	—		$	51,743	$	(313,454	)	$	(30,356	)	$	1,154,757

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

F-6

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1 —	Organization

Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities owning businesses operating under the Copano name since 1992. We, through our subsidiaries, provide 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 Texas, Oklahoma, Wyoming and Louisiana. Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C., its subsidiaries and entities it manages or operates.

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 consumers. 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. We refer to our operations (i) conducted through our subsidiaries operating in Texas and Louisiana collectively as our “Texas” segment, (ii) conducted through our subsidiaries operating in Oklahoma, including our crude oil pipeline which we sold in October 2009, collectively as our “Oklahoma” segment and (iii) conducted through our subsidiaries operating in Wyoming collectively as our “Rocky Mountains” segment.


Note 2 —	Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in our consolidated financial statements.

Because we sold our crude oil pipeline operations in October 2009, the results related to these operations have been classified as “discontinued operations” on the accompanying consolidated statements of operations for the years ended December 31, 2009 and 2008. Unless otherwise indicated, information about the statements of operations that is presented in the notes to consolidated financial statements relates only to our continuing operations. See Note 13.

Our management believes that the disclosures are adequate to make the information presented not misleading. In the preparation of these financial statements, we evaluated subsequent events through the issuance date of the financial statements.

Investments in Unconsolidated Affiliates

Although we are the managing partner or member in each of our equity investments and own a majority interest in some of our equity investments, we account for our investments in unconsolidated affiliates using the equity method of accounting. Equity in earnings from our unconsolidated affiliates is included in income from operations as the operations of each of our unconsolidated affiliates are integral to our operations. See Note 4.

F-7

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Use of Estimates

In preparing the financial statements in conformity with accounting policies generally accepted in the United States of America, management must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although our management believes the estimates are appropriate, actual results can differ materially from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include all highly liquid cash investments with original maturities of three months or less when purchased.

Concentration and Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable, and risk management assets and liabilities.

We place our cash and cash equivalents with large financial institutions. We derive our revenue from customers primarily in the natural gas and utility industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable consists primarily of mid-size to large domestic corporate entities. Counterparties that individually accounted for 5% or more of our 2010 revenue collectively accounted for approximately 73% of our 2010 revenue. As of December 31, 2010, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services. Companies accounting for another approximately 19% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of December 31, 2010, our four largest hedging counterparties accounted for approximately 92% of the value of our net commodity hedging positions and all counterparties were rated A2 and A- or better by Moody’s Investors Service and Standard & Poor’s Ratings Services.

Allowance for Doubtful Accounts

We extend credit to customers and other parties in the normal course of business. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding economic conditions, each party’s ability to make required payments and other factors. As the financial condition of any party changes, other circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of

F-8

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

offset. We also manage our credit risk using prepayments and guarantees to ensure that our management’s established credit criteria are met. The activity in the allowance for doubtful accounts is as follows (in thousands):


	Balance at				Write-Offs,			Balance at
	Beginning		Charged to		Net of			End of
	of Period		Expense		Recoveries			Period

Year ended December 31, 2010	$	211	$	65	$	(104	)	$	172
Year ended December 31, 2009		88		389		(266	)		211
Year ended December 31, 2008		166		1,269		(1,347	)		88

Property, Plant and Equipment

Our property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, gas processing, conditioning, fractionation and treating facilities and other related facilities, and are carried at cost less accumulated depreciation.


	December 31,
	2010			2009
	(In thousands)

Property, plant and equipment, at cost
Pipelines and equipment	$	846,490		$	757,061
Gas processing plants and equipment		270,361			221,126
Construction in progress		9,060			29,457
Office furniture and equipment		12,296			11,845

		1,138,207			1,019,489
Less accumulated depreciation and amortization		(226,050	)		(178,166	)

Property, plant and equipment, net	$	912,157		$	841,323

We charge repairs and maintenance against income when incurred and capitalize renewals and betterments, which extend the useful life or expand the capacity of the assets. We calculate depreciation on the straight-line method based on the estimated useful lives of our assets as follows:


	Useful Lives

Pipelines and equipment		3-30 years
Gas processing plants and equipment		20-30 years
Other property and equipment		3-10 years

We capitalize interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. We capitalized $3,355,000 and $3,362,000 of interest related to major projects during the years ended December 31, 2010 and 2009, respectively.

F-9

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Intangible Assets

Our intangible assets consist of rights-of-way, easements, contracts and acquired customer relationships. Intangible assets consisted of the following (in thousands):


	December 31,
	2010			2009

Rights-of-way and easements, at cost	$	125,496		$	116,122
Less accumulated amortization for rights-of-way and easements		(23,234	)		(18,204	)
Contracts		107,916			107,916
Less accumulated amortization for contracts		(25,153	)		(19,330	)
Customer relationships		4,864			4,864
Less accumulated amortization for customer relationships		(1,304	)		(992	)

Intangible assets, net	$	188,585		$	190,376

We amortize existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable. Initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. During 2010, we did not acquire any rights-of-way with future renewals or extension costs. During 2009, we acquired less than $100,000 of rights-of-way with future renewals or extension costs with a weighted average renewal period of 9 years. For the years ended December 31, 2010 and 2009, the weighted average amortization period for all of our intangible assets was 19 years and 20 years, respectively. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 20 years, 18 years and 12 years, respectively, as of December 31, 2010. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 22 years 19 years and 13 years, respectively, as of December 31, 2009.

Amortization expense was $11,190,000, $11,046,000 and $10,761,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated aggregate amortization expense remaining for each of the five succeeding fiscal years is approximately: 2011 — $11,544,000; 2012 — $11,477,000; 2013 — $11,304,000; 2014 — $11,141,000; and 2015 — $11,106,000.

Impairment of Long-Lived Assets

In accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

F-10

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

regarding the asset, including future commodity prices and estimated future natural gas production in the related region (which is dependent in part on commodity prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:


	•	changes in general economic conditions in which our assets are located;

	•	the availability and prices of natural gas supply;

	•	improvements in exploration and production technology;

	•	the finding and development cost for producers to exploit reserves in a particular area;

	•	our ability to negotiate favorable agreements with producers and customers;

	•	our dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

	•	competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

Goodwill

Goodwill acquired in a business combination is not subject to amortization. As required by ASC 350, “Intangibles — Goodwill and Other,” we test such goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For the years ended December 31, 2010 and 2009, we did not record a goodwill impairment. For the year ended December 31, 2008, we recorded a $2.8 million goodwill impairment related to our acquisition of our Rocky Mountains segment as a result of increased cost of capital during 2008 that reduced the fair value of the these assets below their carrying amount. Goodwill of $0.5 million related to our acquisition of Cimmarron Gathering, LP (“Cimmarron”) is included in other assets as of December 31, 2010 and 2009.

Other Assets

Other assets primarily consist of costs associated with debt issuance costs net of related accumulated amortization. Amortization of other assets is calculated using a method that approximates the effective interest method over the maturity of the associated debt or the term of the associated contract.

Transportation and Exchange Imbalances

In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities we ultimately redeliver. These differences are recorded as transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash-out provisions. Imbalance receivables are included in accounts receivable, and imbalance payables are included in accounts payable on the consolidated balance sheets at current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2010 and 2009, we had imbalance receivables totaling $607,000 and $1,243,000 and imbalance payables totaling $235,000 and $8,000, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

F-11

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result generally from the acquisition, construction, development or normal operation of the asset. When an ARO is incurred, we recognize a liability for the fair value of the ARO and increase the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value and recognized as accretion expense each period, and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss on settlement. We have recorded AROs related to (i) rights-of-way and easements over property we do not own and (ii) regulatory requirements where a legal or contractual obligation exists upon abandonment of the related facility.

The following table presents information regarding our AROs (in thousands):


ARO liability balance, December 31, 2008	$	673
AROs incurred in 2009		19
Accretion for conditional obligations		47

ARO liability balance, December 31, 2009		739
ARO incurred in 2010		50
Accretion for conditional obligations		53

ARO liability balance, December 31, 2010	$	842

Property and equipment at December 31, 2010, 2009 and 2008 includes $560,000, $510,000 and $491,000, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. Also, based on information currently available, we estimate that accretion expense will be approximately $59,000 for 2011, $63,000 for 2012, $67,000 for 2013, $72,000 for 2014 and $78,000 for 2015.

Revenue Recognition

Using the revenue recognition criteria of evidence of an arrangement, delivery of a product and the determination of price, our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue including processing under tolling arrangements. In addition, collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position and their ability to pay.

F-12

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Our most common contractual arrangements for gathering, transporting, processing and conditioning natural gas are summarized below. Substantially all of our Rocky Mountains contracts are fee-based arrangements. Our contracts in Oklahoma and Texas often reflect a combination of pricing terms. In addition to compensating us for gathering, transportation, processing, conditioning or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration or other services. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter in the form of “processing upgrade” payments during periods in which processing margins exceed an agreed-upon amount.

Fee-Based. Under fee-based pricing, producers or shippers pay us an agreed amount per unit of throughput to gather or transport their natural gas and perform other services such as NGL fractionation, transportation and marketing. The revenue we earn from fixed-fee arrangements is directly related to the volume of natural gas or NGLs that flows through our systems and is not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices suppresses drilling and results in a decline in volumes, our fee-based revenues would also decline.

Commodity Sensitive Pricing. Our revenues under the following pricing terms is subject to changes in the prices of natural gas and NGLs.


	•	Percentage-of-Proceeds. Under percentage-of-proceeds arrangements, we generally gather and process natural gas and sell the residue gas and NGL volumes on behalf of a producer at index-related prices. We remit to the producer an agreed upon percentage of the proceeds from the sales of residue gas and NGLs. Under these types of arrangements, our revenues and gross margins increase as natural gas and NGL prices increase and decrease as natural gas and NGL prices decrease.

	•	Percentage-of-Index. Under percentage-of-index arrangements, we purchase natural gas at a percentage discount to a specified index price. We then gather, deliver and resell the natural gas at an index-based price. The gross margins we realize under percentage-of-index arrangements decrease when natural gas prices are low and increase when natural gas prices are high.

	•	Keep-Whole. Under keep-whole arrangements, we receive natural gas from a producer or third-party transporter, process or condition the gas and keep the extracted NGLs for our own account, and sell the NGLs at market prices. We then return to the producer or transporter an amount of residue gas that is equal, in terms of Btu value, to the amount of wellhead gas we received — in other words an amount that keeps the producer or transporter whole.

Risk Management Activities

We engage in risk management activities that take the form of derivative instruments to manage the risks associated with natural gas and NGL prices and the fluctuation in interest rates. Through our risk management activities, we must estimate the fair value of our financial derivatives using valuation models based on whether the inputs to those valuation techniques are observable or unobservable.

ASC 815 “Accounting for Derivative Instruments and Hedging Activities,” as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments

F-13

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

embedded in other contracts, and for hedging activities. In accordance with ASC 815, we recognize all derivatives as either risk management assets or liabilities in our consolidated balance sheets and measure those instruments at fair value. Changes in the fair value of financial instruments over time are recognized into earnings unless specific hedging criteria are met. If the financial instruments meet the hedging criteria, changes in fair value will be recognized in earnings for fair value hedges and in other comprehensive income for the effective portion of cash flow hedges. Ineffectiveness in cash flow hedges is recognized in earnings in the period in which the ineffectiveness occurs. Gains and losses on cash flow hedges are reclassified to operating revenue as the forecasted transactions impact earnings. We included changes in our risk management activities in cash flow from operating activities on the consolidated statements of cash flows.

ASC 815 does not apply to non-derivative contracts or derivative contracts that are subject to a normal purchases and normal sales exclusion. Contracts for normal purchases and normal sales provide for the purchase or sale of something other than a financial instrument or derivative instrument and for delivery in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. Our forward natural gas purchase and sales contracts are either not considered a derivative or are subject to the normal purchases and normal sales scope exception. These contracts generally have terms ranging between one and five years, although a small number continue for the life of the dedicated production.

We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the risks to our cash flow and profitability resulting from changes in commodity prices and interest rates. We recognize these transactions as assets and liabilities on our consolidated balance sheets based on the instrument’s fair value. The majority of our financial instruments have been designated and accounted for as cash flow hedges except as discussed in Note 9.

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820, “Fair Value Measurement”. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. See Note 9 for additional disclosure.

Interest and Other Financing Costs

Interest and other financing costs includes interest and fees incurred and amortization of debt issuance costs related to our senior secured credit facility and senior notes discussed in Note 5, net cash settlements of interest rate swaps, unrealized mark-to-market loss of interest rate swaps and noncash ineffectiveness of interest rate swaps.

Income Taxes

Three of our wholly owned subsidiaries, Copano General Partners, Inc. (“CGP”) and Copano Energy Finance Corporation (“CEFC”), both Delaware corporations, and CPNO Services, L.P. (“CPNO Services”), a Texas limited partnership, are the only entities within our consolidated group subject to federal income taxes. CGP’s operations primarily include its indirect ownership of the managing general partner interest in certain of our Texas operating entities. CEFC was formed in July 2005 and is a co-issuer of our 8.125% senior unsecured notes issued in February 2006 and November 2007, as well as our 7.75% senior unsecured notes issued in May 2008 (see Note 5). CPNO Services allocates administrative and operating costs, including payroll and benefits expenses, to us and certain of our operating subsidiaries. As of December 31, 2010, CGP and CPNO Services have estimated a combined net operating loss (“NOL”) carry forward of approximately $5,784,000, for which a valuation allowance has been recorded. We recognized no significant income tax expense for the years ended December 31, 2010, 2009 and 2008.

F-14

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Except for income allocated with respect to CGP, CEFC and CPNO Services, our income is taxable directly to our unitholders.

We do not provide for federal income taxes in the accompanying consolidated financial statements, as we are not subject to entity-level federal income tax. However, we are subject to the Texas margin tax, which is imposed at a maximum effective rate of 0.7% on our annual “margin,” as defined in the Texas margin tax statute enacted in 2007. Our annual margin generally is calculated as our revenues for federal income tax purposes less the “cost of the products sold” as defined in the statute. The provision for the Texas margin tax totaled $895,000, $794,000 and $1,249,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Under the provisions of ASC 740 “Accounting for Income Taxes,” we are required to record the effects on deferred taxes for a change in tax rates or tax law in the period that includes the enactment date. Under ASC 740, taxes based on income, like the Texas margin tax, are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The deferred tax provisions presented on the accompanying consolidated balance sheets relate to the effect of temporary book/tax timing differences associated with depreciation.

Net Income Per Unit

Net income per unit is calculated in accordance with ASC 260, “Earnings Per Share,” which specifies the use of the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.

Basic net income per unit excludes dilution and is computed by dividing net income attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income per unit reflects potential dilution that could occur if convertible securities were converted into common units or contracts to issue common units were exercised except when the assumed conversion or exercise would have an anti-dilutive effect on net income per unit. Dilutive net income per unit is computed by dividing net income attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.


	Year Ended December 31,
	2010		2009		2008
	(In thousands)

Basic weighted average units		63,854		54,395		48,513
Potentially dilutive common equity:
Employee options		—		93		326
Unit appreciation rights		—		7		—
Restricted units		—		4		47
Phantom units		—		84		19
Contingent incentive plan unit awards		—		78		197
Class C units		—		131		812
Class D units		—		3,246		3,246
Class E units		—		—		4,696

Dilutive weighted average units⁽¹⁾		63,854		58,038		57,856

F-15

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)


(1)		The following potentially dilutive common equity was excluded from the dilutive net income (loss) per unit calculation because to include these equity securities would have been anti-dilutive:


	Year Ended December 31,
	2010		2009		2008
	(In thousands)

Employee options		962		1,210		1,085
Unit appreciation rights		360		296		—
Restricted units		60		101		123
Phantom units		882		614		570
Contingent incentive plan unit awards		64		—		—
Series A preferred units		10,585		—		—

Equity-Based Compensation

We account for equity-based compensation expense in accordance with ASC 718, “Stock Compensation.” We estimate grant date fair value using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. This cost is recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). We estimate anticipated forfeitures and the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. We treat equity awards granted as a single award and recognize equity-based compensation expense on a straight-line basis (net of estimated forfeitures) over the employee service or vesting period. Equity-based compensation expense is recorded in operations and maintenance expenses and general and administrative expenses in our consolidated statements of operations. See Note 6.


Note 3 —	New Accounting Pronouncements

Fair Value Measurements

In January 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements,” which updates ASC 820-10 to require new disclosure of amounts transferred in and out of Level 1 and Level 2 of the fair value hierarchy and presentation of a reconciliation of changes in fair value amounts in the Level 3 fair value hierarchy on a gross basis rather than a net basis. Additionally, ASU 2010-06 requires greater disaggregation of the assets and liabilities for which fair value measurements are presented and requires expanded disclosure of the valuation techniques and inputs used for Level 2 and Level 3 fair value measurements. We adopted ASU 2010-06 on January 1, 2010. See Note 9.


Note 4 —	Investments in Unconsolidated Affiliates

We own a 62.5% equity investment in Webb/Duval Gatherers (“Webb Duval”), a Texas general partnership, a majority interest in Southern Dome, LLC (“Southern Dome”), a Delaware limited liability company, a 51% equity investment in Bighorn Gas Gathering, L.L.C. (“Bighorn”), a Delaware limited liability company, a 37.04% equity investment in Fort Union Gas Gathering, L.L.C. (“Fort Union”), a Delaware limited liability company and a 50% equity investment in Eagle Ford Gathering LLC (“Eagle Ford”), a Delaware limited liability company.

On occasion, the price we pay to acquire an ownership interest in a company or partnership exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in unconsolidated affiliates. At December 31, 2010 and 2009, our investments in Webb Duval, Southern Dome, Bighorn and Fort Union included excess cost amounts totaling $468,708,000 and

F-16

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4 —	Investments in Unconsolidated Affiliates (Continued)

$511,522,000, respectively, all of which were attributable to the fair value of the underlying tangible and intangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities. To the extent that we attribute all or a portion of an excess cost amount to higher fair values, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation. Amortization of such excess cost amounts was $43,824,000, $19,200,000 and $19,116,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

The impairment test for our investments in unconsolidated affiliates requires that we consider whether the fair value of our equity investment as a whole, not the underlying net assets, has declined, and if so, whether that decline is other than temporary. We periodically reevaluate our equity — method investments to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with the ASC 323 “Investments — Equity Method and Joint Ventures.” During the three months ended June 30, 2010, we recorded a $25,000,000 impairment charge relating to our investment in Bighorn primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the CIG forward price curve. During the three months ended December 31, 2010, we recorded a $697,000 impairment in our investment in Webb Duval due to declines in volumes transported on the Webb Duval system.

No restrictions exist under Webb Duval’s, Southern Dome’s, Bighorn’s, or Eagle Ford’s partnership or operating agreements that limit these entities’ ability to pay distributions to their respective partners or members after consideration of their respective current and anticipated cash needs, including debt service obligations. 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 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash. As of December 31, 2010, Fort Union is in compliance with all financial covenants.

Bighorn. Although we own a majority managing member interest in Bighorn, we account for our investment using the equity method of accounting because the minority members have substantive participating rights with respect to the management of Bighorn. Our investment in Bighorn totaled $344,038,000 and $383,135,000 as of December 31, 2010 and 2009, respectively. During the years ended December 31, 2010, 2009 and 2008, we made capital contributions to Bighorn of $848,000, $2,707,000 and $6,586,000, respectively, of which $336,000, $1,129,000 and $4,394,000, respectively, related to nonconsent capital projects we completed independent of other members. We are entitled to a priority distribution of net cash flows from the capital we contributed to nonconsent capital projects up to 140% of the contributed capital. Remaining income of Bighorn is allocated to us based on our ownership interest.

F-17

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4 —	Investments in Unconsolidated Affiliates (Continued)

The summarized financial information for our investment in Bighorn, which is accounted for using the equity method, is as follows (in thousands):


	Year Ended December 31,
	2010			2009			2008

Operating revenue	$	31,435		$	35,980		$	34,854
Operating expenses		(11,552	)		(15,879	)		(13,368	)
Depreciation and amortization		(5,320	)		(10,579	)		(5,171	)
Interest income (expense) and other		95			9			78

Net income (loss)		14,658			9,531			16,393
Ownership %		51	%		51	%		51	%

		7,476			4,861			8,360
Priority allocation of earnings and other		485			702			519
Copano’s share of management fee charged		283			276			241
Amortization of the difference between the carried investment and the underlying equity in net assets and impairment		(36,715	)		(12,791	)		(12,704	)

Equity in loss from unconsolidated affiliates	$	(28,471	)	$	(6,952	)	$	(3,584	)

Distributions	$	11,190		$	12,244		$	11,026

Current assets	$	5,449		$	7,115		$	10,942
Noncurrent assets		88,754			92,617			97,720
Current liabilities		(1,031	)		(1,598	)		(3,395	)
Noncurrent liabilities		(269	)		(238	)		—

Net assets	$	92,903		$	97,896		$	105,267

Fort Union. Our investment in Fort Union totaled $218,491,000 and $221,183,000 as of December 31, 2010 and 2009, respectively. During the years ended December 31, 2010, 2009 and 2008, we made capital contributions to Fort Union of $774,000, $955,000 and $20,246,000, respectively.

F-18

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4 —	Investments in Unconsolidated Affiliates (Continued)

The summarized financial information for our investment in Fort Union, which is accounted for using the equity method, is as follows (in thousands):


	Year Ended December 31,
	2010			2009			2008

Operating revenue	$	58,611		$	63,013		$	52,494
Operating expenses		(7,474	)		(6,857	)		(4,397	)
Depreciation and amortization		(7,739	)		(8,180	)		(6,000	)
Interest income (expense) and other		(3,915	)		(3,509	)		(8,441	)

Net income (loss)		39,483			44,467			33,656
Ownership %		37.04	%		37.04	%		37.04	%

		14,625			16,471			12,466
Priority allocation of earnings and other		—			(287	)		225
Copano’s share of management fee charged		89			84			35
Amortization of the difference between the carried investment and the underlying equity in net assets and impairment		(6,423	)		(6,423	)		(6,423	)

Equity in earnings from unconsolidated affiliates	$	8,291		$	9,845		$	6,303

Distributions	$	11,668		$	13,723		$	9,704

Current assets	$	15,729		$	12,339		$	14,181
Noncurrent assets		204,424			212,416			215,999
Current liabilities		(19,944	)		(21,146	)		(18,978	)
Noncurrent liabilities		(74,203	)		(87,677	)		(105,097	)

Net assets	$	126,006		$	115,932		$	106,105

Other. The summarized financial information for our other unconsolidated investments which included Eagle Ford, Webb Duval and Southern Dome, is presented below in aggregate (in thousands):


	Year Ended December 31,
	2010			2009			2008

Operating revenue	$	30,262		$	23,732		$	45,368
Operating expenses		(25,788	)		(20,011	)		(37,893	)
Depreciation, amortization and impairment⁽¹⁾		(4,654	)		(1,629	)		(1,536	)
Other expense, net		7			5			27

Net (loss) income	$	(173	)	$	2,097		$	5,966

Current assets	$	12,166		$	4,971		$	4,922
Noncurrent assets		75,361			21,957			23,494
Current liabilities		(11,343	)		(6,591	)		(4,450	)
Noncurrent liabilities		(63	)		(58	)		(54	)

Net assets	$	76,121		$	20,279		$	23,912


(1)		In 2010, Webb Duval recorded a $3,139,000 impairment.

F-19

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4 —	Investments in Unconsolidated Affiliates (Continued)

Our share of the equity in (loss) earnings from other unconsolidated affiliates was $(300,000), $1,707,000 and $4,170,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

We received total distributions from our other investments in unconsolidated affiliates of $3,097,000, $3,717,000 and $5,100,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

We made cash contributions to our other unconsolidated affiliates of $30,732,000, $0 and $0 for the years ended December 31, 2010, 2009 and 2008, respectively. Contributions for 2010 were primarily made to Eagle Ford for the construction of gathering lines in the Eagle Ford Shale resource play in Texas.


Note 5 —	Long-Term Debt


	December 31,
	2010		2009
	(In thousands)

Long-term debt:
Credit Facility	$	10,000	$	270,000
Senior Notes:
8.125% senior unsecured notes due 2016		332,665		332,665
Unamortized bond premium-senior notes due 2016		546		628
7.75% senior unsecured notes due 2018		249,525		249,525

Total Senior Notes		582,736		582,818

Total	$	592,736	$	852,818

Senior Secured Revolving Credit Facility

Our $550 million senior secured revolving credit facility (the “Credit Facility”) with Bank of America, N.A., as Administrative Agent, matures on October 18, 2012 and includes 28 lenders with commitments ranging from $1 million to $60 million, with the largest commitment representing 10.9% of the total commitments. Future borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restrictions so long as we are in compliance with its terms, including the financial covenants described below. The Credit Facility provides for up to $50.0 million in standby letters of credit. As of December 31, 2010 and 2009, we had no letters of credit outstanding.

Our obligations under the Credit Facility are secured by first priority liens on substantially all of our assets and the assets of our wholly owned subsidiaries (except for equity interests in Fort Union and certain equity interests acquired with the Cimmarron acquisition), all of which are party to the Credit Facility as guarantors. Our less than wholly owned subsidiaries have not pledged their assets to secure the Credit Facility or guaranteed our obligations under the Credit Facility.

Annual interest under the Credit Facility is determined, at our election, by reference to (i) the British Bankers Association LIBOR rate (“LIBOR”), plus an applicable margin ranging from 1.25% to 2.50% or (ii) the higher of the federal funds rate plus 0.5% or the prime rate plus, in either case, an applicable margin ranging from 0.25% to 1.50%. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period. The effective average interest rate on borrowings under the Credit Facility for the years ended December 31, 2010, 2009 and 2008 was 8.9%, 4.8% and 6.5%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility for those periods, respectively, was 0.25%, 0.25% and 0.25%. Interest and other financing costs

F-20

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)

related to the Credit Facility totaled $5,725,000, $8,299,000 and $11,821,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the Credit Facility and, as of December 31, 2010 and 2009, the unamortized portion of debt issue costs totaled $4,639,000 and $5,999,000, respectively.

The Credit Facility contains various covenants (including certain subjective representations and warranties) that, subject to exceptions, limit our and subsidiary guarantors’ ability to grant liens; make loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the Credit Facility limits us and our subsidiary guarantors’ ability to incur additional indebtedness, subject to exceptions, including (i) purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.

The Credit Facility contains covenants (some of which require that we make certain subjective representations and warranties), including financial covenants that require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios as follows:


	•	a minimum EBITDA to interest expense ratio (using four quarters’ EBITDA as defined under the Credit Facility) of 2.5 to 1.0;

	•	a maximum total debt to EBITDA ratio of 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).

EBITDA for the purposes of the Credit Facility is our EBITDA with certain negotiated adjustments.

At December 31, 2010, our ratio of EBITDA to interest expense was 3.75x, and our ratio of total debt to EBITDA was 3.03x. Based on our current four-quarter EBITDA, as defined under the Credit Facility, we could borrow an additional $400 million before reaching our maximum total debt to EBITDA ratio of 5.0 to 1.0. If we failed to comply with the financial or other covenants under our Credit Facility or experienced a material adverse effect on our operations, business, properties, liabilities or financial or other condition, we would be unable to borrow under our Credit Facility, and could be in default after specified notice and cure periods.

Our Credit Facility also contains customary events of default, including the following:


	•	failure to pay any principal when due, or, within specified grace periods, any interest, fees or other amounts;

	•	failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to certain grace periods in some cases;

	•	default on the payment of any other indebtedness in excess of $5 million, or in the performance of any obligation or condition with respect to such indebtedness, beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;

	•	bankruptcy or insolvency events involving us or our subsidiaries;

	•	our inability to demonstrate compliance with financial covenants within a specified period after Bighorn or Fort Union is prohibited from making a distribution to its members;

	•	the entry of, and failure to pay, one or more adverse judgments in excess of $5 million upon which enforcement proceedings are brought or are not stayed pending appeal; and

	•	a change of control (as defined in the Credit Facility).

F-21

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)

If an event of default exists under the Credit Facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the Credit Facility.

We are in compliance with the financial covenants under the Credit Facility as of December 31, 2010.

Senior Notes

8.125% Senior Notes Due 2016. In February 2006 and November 2007, we issued $225 million and $125 million, respectively, in aggregate principal amount of our 8.125% senior unsecured notes due 2016 (the “2016 Notes”). The 2016 Notes issued in November 2007 priced above par, resulting in a $781,000 bond premium that is being amortized over the remaining term of the 2016 Notes. During November and December 2008, we repurchased, at market prices, and retired $17,335,000 in aggregate principal of the 2016 Notes below par value and recognized a gain of $4,882,000 on the retirement of the debt. The repurchases and retirements were not made pursuant to the redemption provisions of the indenture discussed below.

Interest and other financing costs related to the 2016 Notes totaled $27,802,000, $27,809,000 and $29,470,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Interest on the 2016 Notes is payable each March 1 and September 1. Costs of issuing the 2016 Notes are being amortized over the term of the 2016 Notes and, as of December 31, 2010, the unamortized portion of debt issue costs totaled $4,420,000.

7.75% Senior Notes Due 2018. In May 2008, we issued $300 million in aggregate principal amount of 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2016 Notes, the “Senior Notes”) in a private placement. During November and December 2008, we repurchased, at market prices, and retired $32,250,000 in aggregate principal of the 2018 Notes below par value and recognized a gain of $10,390,000, and in the first quarter of 2009, we repurchased, at market prices, $18,225,000 in aggregate principal and realized a gain of $3,939,000. The repurchases and retirements were not made pursuant to the redemption provisions of the indenture discussed below.

Interest and other financing costs related to the 2018 Notes totaled $19,882,000, $20,434,000 and $15,351,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Interest on the 2018 Notes is payable each June 1 and December 1. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of December 31, 2010, the unamortized portion of debt issue costs totaled $4,035,000.

General. The Senior Notes represent our senior unsecured obligations and rank pari passu in right of payment with all our other present and future senior indebtedness. The Senior Notes are effectively subordinated to all of our secured indebtedness to the extent of the value of the assets securing the indebtedness and to all existing and future indebtedness and liabilities, including trade payables, of our non-guarantor subsidiaries (other than indebtedness and other liabilities owed to us, if any). The Senior Notes rank senior in right of payment to all of our future subordinated indebtedness.

The Senior Notes are jointly, severally, fully and unconditionally guaranteed by all of our 100% owned subsidiaries (other than CEFC, the co-issuer of the Senior Notes). The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our subsidiary guarantors (including under our Credit Facility) to the extent of the value of the assets securing that indebtedness, and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.

F-22

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)

Senior Notes an opportunity to sell us their notes at 101% of the face amount, plus accrued and unpaid interest to date.

The indenture governing the Senior Notes includes covenants that limit our and our subsidiary guarantors’ ability to, among other things:


	•	sell assets;

	•	pay distributions on, redeem or repurchase our units, or redeem or repurchase our subordinated debt;

	•	make investments;

	•	incur or guarantee additional indebtedness or issue preferred units;

	•	create or incur liens;

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

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

	•	engage in transactions with affiliates;

	•	create unrestricted subsidiaries; and

	•	enter into sale and leaseback transactions.

In addition, the indentures governing our Senior Notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the Senior Notes indentures) is at least 1.75x. At December 31, 2010, our ratio of EBITDA to fixed charges was 3.5x, which is in compliance with this incurrence covenant under the indentures governing our Senior Notes.

These covenants are subject to customary exceptions and qualifications. Additionally, if the Senior Notes achieve an investment grade rating from each of Moody’s Investors Service and Standard & Poor’s Ratings Services, many of these covenants will terminate.

We are in compliance with the financial covenants under the Senior Notes as of December 31, 2010.

Condensed consolidating financial information for Copano and its wholly owned subsidiaries is presented below.

F-23

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)


	December 31, 2010																	December 31, 2009
										Investment in																	Investment in
							Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer			Subsidiaries			Subsidiaries		Eliminations			Total			Parent			Co-Issuer			Subsidiaries			Subsidiaries		Eliminations			Total
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	9,650		$	—		$	50,280		$	—	$	—		$	59,930		$	3,861		$	—		$	40,831		$	—	$	—		$	44,692
Accounts receivable, net		14			—			96,648			—		—			96,662			29			—			91,127			—		—			91,156
Intercompany receivable		35,178			(1	)		(35,177	)		—		—			—			21,034			—			(21,034	)		—		—			—
Risk management assets		—			—			7,836			—		—			7,836			—			—			36,615			—		—			36,615
Prepayments and other current assets		3,378			—			1,801			—		—			5,179			3,610			—			1,327			—		—			4,937

Total current assets		48,220			(1	)		121,388			—		—			169,607			28,534			—			148,866			—		—			177,400

Property, plant and equipment, net		56			—			912,101			—		—			912,157			96			—			841,227			—		—			841,323
Intangible assets, net		—			—			188,585			—		—			188,585			—			—			190,376			—		—			190,376
Investment in unconsolidated affiliates		—			—			604,304			604,304		(604,304	)		604,304			—			—			618,503			618,503		(618,503	)		618,503
Investment in consolidated subsidiaries		1,703,940			—			—			—		(1,703,940	)		—			1,684,994			—			—			—		(1,684,994	)		—
Escrow cash		—			—			1,856			—		—			1,856			—			—			1,858			—		—			1,858
Risk management assets		—			—			11,943			—		—			11,943			—			—			15,381			—		—			15,381
Other assets, net		13,128			—			5,413			—		—			18,541			15,854			—			6,717			—		—			22,571

Total assets	$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993		$	1,729,478		$	—		$	1,822,928		$	618,503	$	(2,303,497	)	$	1,867,412

LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	17		$	—		$	117,689		$	—	$	—		$	117,706		$	—		$	—		$	111,021		$	—	$	—		$	111,021
Accrued interest		10,621			—			—			—		—			10,621			11,146			—			775			—		—			11,921
Accrued tax liability		913			—			—			—		—			913			672			—			—			—		—			672
Risk management liabilities		—			—			9,357			—		—			9,357			—			—			9,671			—		—			9,671
Other current liabilities		4,266			—			10,229			—		—			14,495			2,637			—			6,721			—		—			9,358

Total current liabilities		15,817			—			137,275			—		—			153,092			14,455			—			128,188			—		—			142,643

Long-term debt		592,736			—			—			—		—			592,736			852,818			—			—			—		—			852,818
Deferred tax provision		1,848			—			35			—		—			1,883			1,862			—			—			—		—			1,862
Risk management and other noncurrent liabilities		186			—			4,339			—		—			4,525			317			—			9,746			—		—			10,063
Members’/Partners’ capital:
Series A convertible preferred units		285,172			—			—			—		—			285,172			—			—			—			—		—			—
Common units		1,161,652			—			—			—		—			1,161,652			879,504			—			—			—		—			879,504
Class D units		—			—			—			—		—			—			112,454			—			—			—		—			112,454
Paid-in capital		51,743			1			1,162,543			602,055		(1,764,599	)		51,743			42,518			1			1,191,268			595,775		(1,787,044	)		42,518
Accumulated (deficit) earnings		(313,454	)		(2	)		571,754			2,249		(574,001	)		(313,454	)		(158,267	)		(1	)		509,909			22,728		(532,636	)		(158,267	)
Accumulated other comprehensive (loss) income		(30,356	)		—			(30,356	)		—		30,356			(30,356	)		(16,183	)		—			(16,183	)		—		16,183			(16,183	)

		1,154,757			(1	)		1,703,941			604,304		(2,308,244	)		1,154,757			860,026			—			1,684,994			618,503		(2,303,497	)		860,026

Total liabilities and members’/partners’ capital	$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993		$	1,729,478		$	—		$	1,822,928		$	618,503	$	(2,303,497	)	$	1,867,412

F-24

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)


	Year Ended December 31, 2010																	Year Ended December 31, 2009
									Investment in																	Investment in
						Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)

Revenue:
Natural gas sales	$	—		$	—	$	381,453		$	—		$	—		$	381,453		$	—		$	—	$	316,686		$	—		$	—		$	316,686
Natural gas liquids sales		—			—		490,980			—			—			490,980			—			—		406,662			—			—			406,662
Transportation, compression and processing fees		—			—		68,398			—			—			68,398			—			—		55,983			—			—			55,983
Condensate and other		—			—		54,333			—			—			54,333			—			—		40,715			—			—			40,715

Total revenue		—			—		995,164			—			—			995,164			—			—		820,046			—			—			820,046

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		—			—		745,074			—			—			745,074			—			—		576,448			—			—			576,448
Transportation⁽¹⁾		—			—		22,701			—			—			22,701			—			—		24,148			—			—			24,148
Operations and maintenance		—			—		53,487			—			—			53,487			—			—		51,477			—			—			51,477
Depreciation and amortization		40			—		62,532			—			—			62,572			40			—		56,935			—			—			56,975
General and administrative		19,536			—		20,811			—			—			40,347			19,329			—		20,182			—			—			39,511
Taxes other than income		—			—		4,726			—			—			4,726			—			—		3,732			—			—			3,732
Equity in loss (earnings) from unconsolidated
affiliates		—			—		20,480			20,480			(20,480	)		20,480			—			—		(4,600	)		(4,600	)		4,600			(4,600	)

Total costs and expenses		19,576			—		929,811			20,480			(20,480	)		949,387			19,369			—		728,322			(4,600	)		4,600			747,691

Operating (loss) income		(19,576	)		—		65,353			(20,480	)		20,480			45,777			(19,369	)		—		91,724			4,600			(4,600	)		72,355
Other income (expense):
Interest and other income		—			—		78			—			—			78			—			—		1,202			—			—			1,202
Gain on retirement of unsecured debt		—			—		—			—			—			—			3,939			—		—			—			—			3,939
Interest and other financing costs		(50,054	)		—		(3,551	)		—			—			(53,605	)		(53,180	)		—		(2,656	)		—			—			(55,836	)

(Loss) income before income taxes, discontinued operations
and equity in earnings from consolidated subsidiaries		(69,630	)		—		61,880			(20,480	)		20,480			(7,750	)		(68,610	)		—		90,270			4,600			(4,600	)		21,660
Provision for income taxes		(896	)		—		(35	)		—			—			(931	)		(794	)		—		—			—			—			(794	)

(Loss) income before discontinued operations and equity
in earnings from consolidated subsidiaries		(70,526	)		—		61,845			(20,480	)		20,480			(8,681	)		(69,404	)		—		90,270			4,600			(4,600	)		20,866
Discontinued operations, net of tax		—			—		—			—			—			—			—			—		2,292			—			—			2,292

(Loss) income before equity earnings from consolidated
subsidiaries		(70,526	)		—		61,845			(20,480	)		20,480			(8,681	)		(69,404	)		—		92,562			4,600			(4,600	)		23,158
Equity in earnings from consolidated subsidiaries		61,845			—		—			—			(61,845	)		—			92,562			—		—			—			(92,562	)		—

Net income (loss)		(8,681	)		—		61,845			(20,480	)		(41,365	)		(8,681	)		23,158			—		92,562			4,600			(97,162	)		23,158
Preferred unit distributions		(15,188	)		—		—			—			—			(15,188	)		—			—		—			—			—			—

Net (loss) income to common units	$	(23,869	)	$	—	$	61,845		$	(20,480	)	$	(41,365	)	$	(23,869	)	$	23,158		$	—	$	92,562		$	4,600		$	(97,162	)	$	23,158


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

F-25

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)


	Year Ended December 31, 2008
									Investment in
						Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)

Revenue:
Natural gas sales	$	—		$	—	$	747,258		$	—		$	—		$	747,258
Natural gas liquids sales		—			—		597,986			—			—			597,986
Transportation, compression and processing fees		—			—		59,006			—			—			59,006
Condensate and other		—			—		50,169			—			—			50,169

Total revenue		—			—		1,454,419			—			—			1,454,419

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		—			—		1,178,304			—			—			1,178,304
Transportation⁽¹⁾		—			—		21,971			—			—			21,971
Operations and maintenance		948			—		52,876			—			—			53,824
Depreciation, amortization and impairment		44			—		52,872			—			—			52,916
General and administrative		25,610			—		19,961			—			—			45,571
Taxes other than income		—			—		3,019			—			—			3,019
Equity in (earnings) loss from unconsolidated affiliates		—			—		(6,889	)		(6,889	)		6,889			(6,889	)

Total costs and expenses		26,602			—		1,322,114			(6,889	)		6,889			1,348,716

Operating (loss) income		(26,602	)		—		132,305			6,889			(6,889	)		105,703
Other income (expense):
Interest and other income		47			—		1,127			—			—			1,174
Gain on retirement of unsecured debt		15,272			—		—			—			—			15,272
Interest and other financing costs		(53,172	)		—		(11,806	)		—			—			(64,978	)

(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries		(64,455	)		—		121,626			6,889			(6,889	)		57,171
Provision for income taxes		(1,249	)		—		—			—			—			(1,249	)

(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries		(65,704	)		—		121,626			6,889			(6,889	)		55,922
Discontinued operations, net of tax		—			—		2,291			—			—			2,291

(Loss) income before equity earnings from consolidated subsidiaries		(65,704	)		—		123,917			6,889			(6,889	)		58,213
Equity in earnings from consolidated subsidiaries		123,917			—		—			—			(123,917	)		—

Net income (loss)		58,213			—		123,917			6,889			(130,806	)		58,213
Preferred unit distributions		—			—		—			—			—			—

Net income (loss) to common units	$	58,213		$	—	$	123,917		$	6,889		$	(130,806	)	$	58,213


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

F-26

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)


	Year Ended December 31, 2010																	Year Ended December 31, 2009
									Investment in																	Investment in
						Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)

Cash Flows From Operating Activities:
Net cash (used in) provided by operating activities	$	(75,621	)	$	—	$	199,219		$	22,416		$	(22,416	)	$	123,598		$	25,217		$	—	$	116,101		$	20,931		$	(20,931	)	$	141,318

Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—		(127,703	)		—			—			(127,703	)		—			—		(76,292	)		—			—			(76,292	)
Acquisitions, net of cash acquired		—			—		—			—			—						—			—		(2,840	)		—			—			(2,840	)
Investment in unconsolidated affiliates		—			—		(33,002	)		(33,002	)		33,002			(33,002	)		—			—		(4,228	)		(4,228	)		4,228			(4,228	)
Distributions from unconsolidated affiliates		—			—		3,539			3,539			(3,539	)		3,539			—			—		8,753			8,753			(8,753	)		8,753
Investment in consolidated affiliates		(82,415	)		—		—			—			82,415			—			(105	)		—		—			—			105			—
Distributions from consolidated affiliates		115,455			—		—			—			(115,455	)		—			47,675			—		—			—			(47,675	)		—
Proceeds from sale of assets		—			—		447			—			—			447			—			—		6,061			—			—			6,061
Other		—			—		(11	)		—			—			(11	)		—			—		(2,421	)		1			(1	)		(2,421	)

Net cash provided by (used in) investing activities		33,040			—		(156,730	)		(29,463	)		(3,577	)		(156,730	)		47,570			—		(70,967	)		4,526			(52,096	)		(70,967	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		100,000			—		—			—			—			100,000			70,000			—		—			—			—			70,000
Repayments of long-term debt		(360,000	)		—		—			—			—			(360,000	)		(20,000	)		—		—			—			—			(20,000	)
Deferred financing costs		(995	)		—		—			—			—			(995	)		—			—		—			—			—			—
Retirement of unsecured debt		—			—		—			—			—			—			(14,286	)		—		—			—			—			(14,286	)
Distributions to unitholders		(145,531	)		—		—			—			—			(145,531	)		(125,721	)		—		—			—			—			(125,721	)
Equity offering of common units		164,786			—		—			—			—			164,786			—			—		—			—			—			—
Equity offering of common units-offering costs		(6,395	)		—		—			—			—			(6,395	)		—			—		—			—			—			—
Equity offering of Series A convertible preferred units		291,065			—		—			—			—			291,065			—			—		—			—			—			—
Contributions from parent		—			—		82,415			—			(82,415	)		—			—			—		105			—			(105	)		—
Distributions to parent		—			—		(115,455	)		—			115,455			—			—			—		(47,675	)		—			47,675			—
Other		5,440			—		—			33,002			(33,002	)		5,440			664			—		—			4,227			(4,227	)		664

Net cash provided by (used in) financing activities		48,370			—		(33,040	)		33,002			38			48,370			(89,343	)		—		(47,570	)		4,227			43,343			(89,343	)

Net increase (decrease) in cash and cash equivalents		5,789			—		9,449			25,955			(25,955	)		15,238			(16,556	)		—		(2,436	)		29,684			(29,684	)		(18,992	)
Cash and cash equivalents, beginning of year		3,861			—		40,831			59,896			(59,896	)		44,692			20,417			—		43,267			30,212			(30,212	)		63,684

Cash and cash equivalents, end of year	$	9,650		$	—	$	50,280		$	85,851		$	(85,851	)	$	59,930		$	3,861		$	—	$	40,831		$	59,896		$	(59,896	)	$	44,692

F-27

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)


	Year Ended December 31, 2008
									Investment in
						Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
	(In thousands)

Cash Flows From Operating Activities:
Net cash (used in) provided by operating activities	$	(155,565	)	$	—	$	245,489		$	22,460		$	(22,460	)	$	89,924

Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—		(161,722	)		—			—			(161,722	)
Acquisitions, net of cash acquired		—			—		(12,655	)		—			—			(12,655	)
Investment in unconsolidated affiliates		—			—		(26,832	)		(26,832	)		26,832			(26,832	)
Distributions from unconsolidated affiliates		—			—		3,370			3,370			(3,370	)		3,370
Investment in consolidated affiliates		(22,990	)		—		—			—			22,990			—
Distributions from consolidated affiliates		89,000			—		—			—			(89,000	)		—
Proceeds from sale of assets		—			—		28			—			—			28
Other		—			—		(1,044	)		(1	)		1			(1,044	)

Net cash provided by (used in) investing activities		66,010			—		(198,855	)		(23,463	)		(42,547	)		(198,855	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		579,000			—		—			—			—			579,000
Repayments of long-term debt		(339,000	)		—		—			—			—			(339,000	)
Deferred financing costs		(6,684	)		—		(4	)		—			—			(6,688	)
Retirement of unsecured debt		(34,313	)		—		—			—			—			(34,313	)
Distributions to unitholders		(104,234	)		—		—			—			—			(104,234	)
Equity offering of common units-offering costs		(47	)		—		—			—			—			(47	)
Contributions from parent		—			—		22,990			—			(22,990	)		—
Distributions to parent		—			—		(89,000	)		—			89,000			—
Other		5,232			—		—			26,833			(26,833	)		5,232

Net cash provided by (used in) financing activities		99,954			—		(66,014	)		26,833			39,177			99,950

Net increase (decrease) in cash and cash equivalents		10,399			—		(19,380	)		25,830			(25,830	)		(8,981	)
Cash and cash equivalents, beginning of year		10,018			—		62,647			4,382			(4,382	)		72,665

Cash and cash equivalents, end of year	$	20,417		$	—	$	43,267		$	30,212		$	(30,212	)	$	63,684

F-28


Note 5 —	Long-Term Debt (Continued)

Scheduled Maturities of Long-Term Debt

Scheduled maturities of long-term debt as of December 31, 2010 were as follows (in thousands):


	Principal
Year	Amount

2011	$	—
2012		10,000
2013		—
2014		—
2015		—
Thereafter		582,190

	$	592,190


Note 6 —	Members’ Capital and Distributions

Series A Convertible Preferred Units

On July 21, 2010, we issued 10,327,022 Series A convertible preferred units (“Series A preferred units”) in a private placement to TPG Copenhagen, L.P. (“TPG”), an affiliate of TPG Capital, L.P. for gross proceeds of $300 million. The preferred units were priced at $29.05 per unit, a 10% premium to the 30-day volume-weighted average closing price of our common units on July 19, 2010, two trading days before the date we issued the preferred units. We used $180.0 million of the net proceeds to repay the then-outstanding balance under our Credit Facility. We used the remaining net proceeds to fund our expansion strategy in the Eagle Ford Shale resource play and other growth initiatives in Texas and Oklahoma.

The Series A preferred units are classified as permanent equity, as they do not meet the criteria of a liability within the scope of ASC 480-10, “Distinguishing Liabilities from Equity,” nor do they meet the criteria of the mezzanine level under ASC 815, “Accounting for Derivative Instruments and Hedging Activities.” Additionally, none of the identified embedded derivatives relating to the terms of the Series A preferred units requires bifurcation, as each embedded derivative was determined to be clearly and closely related to the host contract of the Series A preferred units under ASC 815-15, “Embedded Derivatives.” As discussed below, the distribution payment under the terms of the Series A preferred units is not discretionary during the first three years and, therefore, the commitment date was determined to be the date of original issuance under ASC 470-20-30, “Debt With Conversions and Other Options.” Further, the change of control provision under the agreement does not preclude the establishment of a commitment date, as it is outside the control of Copano and the Series A preferred unitholder.

Distributions. The Series A preferred units are senior to our common units with respect to rights to distributions. For the first three years after the date on which they were issued, the Series A preferred units are entitled to quarterly distributions in kind (paid in the form of additional Series A preferred units). In-kind distributions will equal $0.72625 per preferred unit per quarter (or 10% per year of the purchase price of a Series A preferred unit) divided by the $29.05 issue price. Beginning with the distribution for the quarter ending September 30, 2013, and through the distribution for the quarter ending June 30, 2016, we are entitled to elect whether to pay preferred distributions in cash, in kind or in a combination of both. For quarters ending after June 30, 2016, we will be obligated to pay preferred distributions in cash unless our available cash (after reserves established by our Board of Directors) is not sufficient to fund the distribution or we and the preferred unitholder agree that a distribution will be paid in kind. Cash distributions on the Series A preferred units will equal the greater of $0.72625 per preferred unit per quarter or the quarterly per-unit distribution paid to our common unitholders for the applicable quarter. In kind distributions for the year ended December 31, 2010 totaled $15,188,000.

Voting Rights. At a special meeting held on November 17, 2010, our common unitholders approved full voting rights for all Series A preferred units. Each Series A preferred unit entitles the holder to one vote.

F-29

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


Note 6 —	Members’ Capital and Distributions (Continued)

Conversion. At the special meeting referred to above, our common unitholders also approved full convertibility of all Series A preferred units into common units on a one-for-one basis. Beginning on July 21, 2013, the Series A preferred units will generally become convertible into common units by us or by the preferred unitholder, subject to the conditions described below. After July 21, 2013, the preferred unitholder may elect to convert all or any portion of its Series A preferred units into common units at any time, but only to the extent that conversion will not cause our estimated ratio of total distributable cash flow to per-unit distributions (for all of our outstanding common and Series A preferred units) to fall below 100% over any of the forecasted succeeding four quarters. In addition, we will have the right to force conversion of all or any portion of the Series A preferred units if the daily volume-weighted average trading price and the average daily trading volume of our common units exceed $37.77 and 500,000 units, respectively, for 20 trading days out of the trailing 30-day period prior to our notice of conversion. On the date of conversion, the rights of the converting Series A preferred units will cease; the converting Series A preferred units will no longer be outstanding and will represent only the right to receive common units at the rate of one common unit for each preferred unit.

Rights upon a Change of Control. The preferred unitholder has conversion rights with respect to certain change of control events. Before consummating a transaction in which any person, other than the preferred unitholder, becomes the beneficial owner, directly or indirectly, of more than 50% of our voting securities, we will make an irrevocable offer (a “change of control offer”) to the preferred unitholder to convert all, but not less than all, of such holder’s Series A preferred units into common units, subject to certain conditions and limitations. Series A preferred units converting in the context of a change of control offer would not convert into common units on a one-for-one basis. Instead, the number of common units we would issue upon conversion of Series A preferred units would equal the quotient of (a) 110% of the aggregate preferred unit issue price for such preferred unitholder’s converting Series A preferred units and all accrued and unpaid distributions on such Series A preferred units as of the date of the change of control offer, divided by (b) $29.05. The preferred unitholder is under no obligation to accept a change of control offer.

Dissolution and Liquidation. The Series A preferred units are senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of Series A preferred units will rank equally with the rest of our common units with respect to rights on dissolution and liquidation.

Common Units

In March 2010, we issued 7,446,250 common units in an underwritten public offering (including units issued upon the underwriters’ exercise of their option to purchase additional units). We used the net proceeds from the offering to repay a portion of our then-outstanding balance under our Credit Facility.

F-30

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


Note 6 —	Members’ Capital and Distributions (Continued)

Distributions. The following table sets forth information regarding distributions to our unitholders for the quarterly periods indicated:


	Distribution
Quarter Ending	Per unit		Date Declared		Record Date		Payment Date		Amount

December 31, 2007	$	0.510		January 16, 2008		February 1, 2008		February 14, 2008	$	24,336,000
March 31, 2008	$	0.530		April 16, 2008		May 1, 2008		May 15, 2008	$	25,506,000
June 30, 2008	$	0.560		July 16, 2008		August 1, 2008		August 14, 2008	$	27,242,000
September 30, 2008	$	0.570		October 15, 2008		November 3, 2008		November 14, 2008	$	27,969,000
December 31, 2008	$	0.575		January 14, 2009		February 2, 2009		February 13, 2009	$	31,466,000
March 31, 2009	$	0.575		April 15, 2009		May 1, 2009		May 15, 2009	$	31,748,000
June 30, 2009	$	0.575		July 15, 2009		August 3, 2009		August 13, 2009	$	31,871,000
September 30, 2009	$	0.575		October 14, 2009		November 2, 2009		November 12, 2009	$	31,860,000
December 31, 2009	$	0.575		January 13, 2010		February 1, 2010		February 11, 2010	$	31,911,000
March 31, 2010	$	0.575		April 14, 2010		April 30, 2010		May 13, 2010	$	38,134,000
June 30, 2010	$	0.575		July 14, 2010		August 2, 2010		August 12, 2010	$	38,295,000
September 30, 2010	$	0.575		October 13, 2010		November 1, 2010		November 11, 2010	$	38,349,000
December 31, 2010	$	0.575		January 12, 2011		February 1, 2011		February 11, 2011	$	38,456,000

Class C Units

Class C units totaling 1,579,409 converted into common units on a one-for-one basis in four equal installments in November 2007, May 2008, November 2008 and May 2009.

Class D Units

Class D units totaling 3,245,817 as of December 31, 2009 converted into our common units on a one-for-one basis in February 2010.

Class E Units

Class E units totaling 5,598,836 converted to common units on a one-for-one basis as of March 13, 2008.

Pre-IPO Investors

Pursuant to our limited liability company agreement, certain of our investors existing prior to our initial public offering (the “Pre-IPO Investors”) agreed to reimburse us for general and administrative expenses in excess of stated levels for a period of three years beginning on January 1, 2005. We received the final reimbursement of $4,103,000 in 2008.

Accounting for Equity-Based Compensation

As discussed in Note 2, we use ASC 718, “Stock Compensation,” to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”). As of December 31, 2010, the number of units available for grant under our LTIP totaled 1,332,132, of which up to 764,358 units were eligible to be issued as restricted common units, phantom units or unit awards.

Restricted Common Units. An award of restricted common units is valued based on the closing price of our common units on the date of grant. The aggregate intrinsic value of our restricted common units, net of anticipated forfeitures, is amortized into expense over the respective vesting periods of the awards. We recognized non-cash

F-31

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


Note 6 —	Members’ Capital and Distributions (Continued)

compensation expense of $1,240,000, $1,542,000 and $1,781,000 related to the amortization of restricted common units outstanding during the years ended December 31, 2010, 2009 and 2008, respectively.

A summary of restricted common unit activity is provided below:


	2010					2009					2008
				Weighted					Weighted					Weighted
				Average					Average					Average
	Number of			Grant-		Number of			Grant-		Number of			Grant-
	Restricted			Date Fair		Restricted			Date Fair		Restricted			Date Fair
	Units			Value		Units			Value		Units			Value

Outstanding at beginning of year		105,501		$	21.45		169,769		$	22.35		241,181		$	22.92
Granted		24,000			29.29		18,000			18.85		18,000			12.61
Vested		(69,329	)		21.88		(76,782	)		22.39		(89,122	)		21.94
Vested-not released		—			—		—			—		395			20.25
Forfeited		(220	)		23.26		(5,486	)		27.67		(685	)		20.95

Outstanding at end of year		59,952		$	24.09		105,501		$	21.45		169,769		$	22.35

As of December 31, 2010, unrecognized compensation costs related to outstanding restricted common units totaled $1,196,000. The expense is expected to be recognized over an approximate weighted average period of 2.1 years. The total fair value of restricted common units that vested during the years ended December 31, 2010, 2009 and 2008 was $1,962,000, $1,380,000 and $2,498,000, respectively.

Phantom Units. An award of phantom units is valued based on the closing price of our common units on the date of grant. The aggregate intrinsic value of our phantom units, net of anticipated forfeitures, is amortized into expense over the respective vesting periods of the awards. We recognized non-cash compensation expense of $5,303,000, $4,125,000 and $2,972,000 related to the amortization of phantom units outstanding during the years ended December 31, 2010, 2009 and 2008, respectively.

In June 2008, we issued performance-based phantom units under our LTIP. These awards vest in three equal installments on each May 15 following the grant date, provided a performance goal for the applicable measurement period is met. The number of performance-based phantom units to vest is dependent on the level of achievement of the performance goal, which is a specified percentage of total return to holders of our common units based on the market price of our common units. These awards were valued using a Monte Carlo simulation technique, an approved valuation method under ASC 718. The model utilized the change in the unit price over time, estimated future distributions, estimated risk-free rate of return, annual volatility and projected rate of error to establish the grant date fair value of the awards. The performance-based phantom unit award also includes an opportunity at the end of the three-year period to earn a bonus in units totaling up to 50% of the award, provided that the performance goal, which is based on total return to Copano unitholders for the three-year period, is met. No performance-based phantom units were issued under the LTIP prior to this issuance. The fair value of phantom unit awards not containing performance conditions is measured using the closing price of our common units on the date of grant.

On June 4, 2010, we granted performance-based phantom units to certain management employees. The number of performance-based phantom units to vest is dependent on the level of achievement of a specified performance goal during the period from the grant date through the cliff vesting date of May 15, 2013 and could be up to 200% greater than the number of awards issued on the grant date if all specified performance goals are met. For awards containing performance conditions that affect vesting, compensation expense recognized is equal to the ultimate outcome of the performance condition.

F-32

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


Note 6 —	Members’ Capital and Distributions (Continued)

A summary of the phantom unit activity is provided below:


	2010					2009					2008
				Weighted					Weighted					Weighted
				Average					Average					Average
	Number of			Grant-		Number of			Grant-		Number of			Grant-
	Phantom			Date Fair		Phantom			Date Fair		Phantom			Date Fair
	Units			Value		Units			Value		Units			Value

Outstanding at beginning of year		698,136		$	28.46		588,910		$	34.18		100,795		$	40.81
Granted		314,290			24.60		225,700			15.39		532,248			32.40
Vested		(91,252	)		25.41		(41,769	)		38.43		(39,477	)		26.55
Vested-not released		—			—		(450	)		38.78		450			38.78
Cancelled		—			—		(11,941	)		17.49		—			—
Forfeited		(39,536	)		31.73		(62,314	)		30.61		(5,106	)		38.06

Outstanding at end of year		881,638		$	27.25		698,136		$	28.46		588,910		$	34.18

As of December 31, 2010, unrecognized compensation expense related to outstanding phantom units totaled $14,747,000. The expense is expected to be recognized over an approximate weighted average period of 2.6 years. The total fair value of phantom units that vested during the years ended December 31, 2010, 2009 and 2008 was $2,313,000, $630,000 and $886,000, respectively.

Unit Options. The fair value of a unit option award, net of anticipated forfeitures, is amortized into expense over the option’s vesting period. We recognized non-cash compensation expense of $772,000, $796,000 and $899,000 related to unit options, net of anticipated forfeitures, for the years ended December 31, 2010, 2009 and 2008, respectively.

F-33

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


Note 6 —	Members’ Capital and Distributions (Continued)

A summary of unit option activity under our LTIP is provided below:


	2010						2009					2008
	Number of			Weighted			Number of			Weighted		Number of			Weighted
	Units			Average			Units			Average		Units			Average
	Underlying			Exercise			Underlying			Exercise		Underlying			Exercise
	Options			Price			Options			Price		Options			Price

Outstanding at beginning of year		1,302,476		$	23.86			1,411,006		$	23.78		1,442,847		$	22.60
Granted^(a)		—			—			33,000			14.89		191,500			32.05
Exercised		(312,695	)		17.40			(61,782	)		10.75		(71,722	)		15.74
Cancelled		(14,960	)		37.75			(19,864	)		28.87		(37,040	)		14.79
Forfeited		(12,462	)		31.78			(59,884	)		28.95		(114,579	)		30.62

Outstanding at end of year		962,359		$	25.64			1,302,476		$	23.86		1,411,006		$	23.78

Aggregate intrinsic value at end of year	$	9,016,000					$	5,430,000				$	453,000
Weighted average remaining contractual term		5.7 years						6.5 years					7.4 years
Exercisable Options:
Outstanding at end of year		689,745		$	23.45			783,031		$	20.65		556,866		$	18.60
Aggregate intrinsic value at end of year	$	7,797,000					$	4,493,000				$	329,000
Weighted average remaining contractual term		5.3 years						5.9 years					6.7 years
Weighted average fair value of option granted						^(a)				$	2.07				$	3.00
Options expected to vest:
At end of year		866,123		$	25.64			1,172,228		$	23.86		1,269,905		$	23.78
Aggregate intrinsic value at end of year	$	8,114,000					$	4,887,000				$	408,000
Weighted average remaining contractual term		5.7 years						6.5 years					7.4 years


(a)		- We did not grant any unit options during the year ended December 31, 2010.

Exercise prices for unit options outstanding as of December 31, 2010 ranged from $10.00 to $44.14.

The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility and distribution yield rates are based on the average of our historical common unit prices and distribution rates and those of similar companies. The expected term of unit options is based on the simplified method and represents the period of time that unit options granted are expected to be outstanding.

F-34

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


Note 6 —	Members’ Capital and Distributions (Continued)


	Year Ended December 31,^(a)
	2009			2008

Weighted average exercise price	$	14.89		$	32.05
Expected volatility		29.8-32.3	%		20.0-20.7	%
Distribution yield		6.68-6.99	%		6.18-6.59	%
Risk-free interest rate		1.71-3.28	%		1.76-3.94	%
Expected term (in years)		6.5			6.5
Weighted average grant-date fair value of options granted	$	2.07		$	3.00
Total intrinsic value of options exercised	$	508,000		$	1,117,000


(a)		- We did not grant any unit options during the year ended December 31, 2010.

As of December 31, 2010, unrecognized compensation costs related to outstanding unit options issued under our LTIP totaled $687,000. The expense is expected to be recognized over a weighted average period of approximately 1.8 years.

Unit Appreciation Rights. The fair value of a unit appreciation right (“UAR”) award, net of anticipated forfeitures, is amortized into expense over the UAR’s vesting period. We recognized non-cash compensation expense of $301,000, $376,000 and $0 related to UARs, net of anticipated forfeitures, for the years ended December 31, 2010, 2009 and 2008, respectively.

A summary of UAR activity is provided below:


	2010					2009
	Number of			Weighted		Number of			Weighted
	Units			Average		Units			Average
	Underlying			Exercise		Underlying			Exercise
	UARs			Price		UARs			Price

Outstanding at beginning of year		302,900		$	15.40		—		$	—
Granted		91,100			25.67		320,000			15.38
Exercised		(28,870	)		15.56		—			—
Cancelled		(40	)		15.09		—			—
Forfeited		(4,640	)		18.53		(17,100	)		15.09

Outstanding at end of year		360,450		$	17.94		302,900		$	15.40

Aggregate intrinsic value at end of year	$	5,697,000				$	4,664,000
Weighted average remaining contractual term		5.2 years					4.8 years
Exercisable UARs:
Outstanding at end of year		32,150		$	18.55		200		$	15.09
Aggregate intrinsic value at end of year	$	596,000				$	2,000
Weighted average remaining contractual term		3.5 years					4.4 years
Weighted average fair value of option granted				$	3.42				$	3.01
UARs expected to vest:
At end of year		324,405		$	17.94		272,610		$	15.40
Aggregate intrinsic value at end of year	$	5,127,300				$	4,197,600
Weighted average remaining contractual term		5.2 years					4.8 years

Exercise prices for UARs outstanding as of December 31, 2010 ranged from $15.09 to $29.93.

F-35

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


Note 6 —	Members’ Capital and Distributions (Continued)

The fair value of each UAR granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the UAR is based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility and distribution yield rates are based on the average of our historical common unit prices and distribution rates and those of similar companies. The expected term of UARs is based on the simplified method and represents the period of time that UARs granted are expected to be outstanding.


	Year Ended December 31,
	2010			2009

Weighted average exercise price	$	17.94		$	15.40
Expected volatility		30.6-31.0	%		30.8-64.8	%
Distribution yield		7.11-7.20	%		6.76-8.47	%
Risk-free interest rate		1.86-3.46	%		0.90-3.18	%
Expected term (in years)		6.5			1.8-5.8
Weighted average grant-date fair value of appreciation rights granted	$	3.42		$	3.01
Total intrinsic value of appreciation rights exercised	$	340,000		$	—

As of December 31, 2010, unrecognized compensation costs related to outstanding UARs totaled $533,000. The expense is expected to be recognized over a weighted average period of approximately 3.4 years.

Unit Awards. In February 2009, we amended our LTIP to provide for unit awards, which are awards of common units that are not subject to vesting or forfeiture. For the year ended December 31, 2010, we granted 97,788 unit awards under our LTIP with a weighted average fair value of $24.89 to settle bonuses, including obligations under our Management Incentive Compensation Plan (“MICP”) and Employee Incentive Compensation Program (“EICP”).

Since ASC 480, “Accounting for Certain Financial Instruments With Characteristics of Both Liabilities and Equity,” requires unconditional obligations in the form of units that the issuer must or may settle by issuing a variable number of units to be classified as a liability, we classify equity awards issued to settle EICP and the MICP obligations as liability awards. As of December 31, 2010, we accrued $600,000 and $1,573,000 for the fourth quarter 2010 EICP bonuses and an estimate of the 2010 MICP incentive bonuses, respectively.

As of December 31, 2010, the estimated unrecognized compensation costs related to outstanding liability awards totaled $262,000 for the MICP which is expected to be recognized as expense on a straight-line basis through February 2011.

F-36

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


Note 7 —	Related Party Transactions

Natural Gas and Related Transactions

The following table summarizes transactions between us and affiliated entities (in thousands):


	Year Ended December 31,
	2010			2009		2008

Affiliates of Mr. Lawing:⁽¹⁾
Natural gas sales⁽²⁾	$	24		$	3	$	113
Gathering and compression services⁽³⁾		11			18		22
Natural gas purchases⁽⁴⁾		510			1,070		1,426
Reimbursements paid⁽⁵⁾		—			2,865		3,236
Reimbursable costs⁽⁶⁾		264			—		—
Payable by us as of December 31, 2010 and 2009⁽⁷⁾		17			147
Webb Duval:
Natural gas sales⁽²⁾		129			923		590
Natural gas purchases⁽⁴⁾		(47	)		562		2,542
Transportation costs⁽⁸⁾		238			334		379
Management fees⁽⁹⁾		224			221		216
Reimbursable costs⁽⁹⁾		967			614		654
Payable to us as of December 31, 2010 and 2009⁽¹⁰⁾		515			910
Payable by us as of December 31, 2010 and 2009⁽⁷⁾		175			321
Eagle Ford:
Management fees⁽⁹⁾		81			—		—
Reimbursable costs⁽⁹⁾		5,760			—		—
Capital project fees⁽⁹⁾		600			—		—
Payable to us as of December 31, 2010⁽¹⁰⁾		12
Payable by us as of December 31, 2010⁽⁷⁾		1
Southern Dome:
Management fees⁽⁹⁾		250			250		250
Reimbursable costs⁽⁹⁾		354			328		599
Payable to us as of December 31, 2010 and 2009⁽¹⁰⁾		18			586
Bighorn:
Compressor rental fees⁽¹¹⁾		1,666			981		—
Gathering costs⁽⁸⁾		16			309		603
Natural gas purchases⁽⁴⁾		3			25		30
Management fees⁽⁹⁾		556			357		287
Reimbursable costs⁽⁹⁾		2,473			3,121		252
Payable to us as of December 31, 2010 and 2009⁽¹⁰⁾		44			490
Payable by us as of December 31, 2010 and 2009⁽⁷⁾		3			23
Fort Union:
Gathering costs⁽⁸⁾		5,224			8,259		8,440
Treating costs⁽⁴⁾		52			199		856
Management fees⁽⁹⁾		239			212		—
Reimbursable costs⁽⁹⁾		892			1,419		95
Payable to us as of December 31, 2010 and 2009⁽¹⁰⁾		18			634
Payable by us as of December 31, 2010 and 2009⁽⁷⁾		2			162
Other:
Natural gas sales⁽²⁾		190			270		423
Natural gas liquids sales⁽¹¹⁾		—			3		—
Payable to us as of December 31, 2010 and 2009⁽¹⁰⁾		—			137
Payable by us as of December 31, 2010 and 2009⁽⁷⁾		16			—

F-37

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


Note 7 —	Related Party Transactions (Continued)


(1)		These entities were controlled by John R. Eckel, Jr., our former Chairman of the Board of Directors and Chief Executive Officer, until his death in November 2009, and since that time have been controlled by Douglas L. Lawing, our Executive Vice President, General Counsel and Secretary.

(2)		Revenues included in natural gas sales on our consolidated statements of operations.

(3)		Revenues included in transportation, compression and processing fees on our consolidated statements of operations.

(4)		Included in costs of natural gas and natural gas liquids on our consolidated statements of operations.

(5)		Reimbursable costs paid to Copano/Operations, Inc. (“Copano Operations”) for our use of shared personnel, office space, equipment, goods and services under an agreement that terminated on January 1, 2010. Copano Operations provided certain management, operations and administrative support services to us pursuant to an administrative and operating services agreement. Copano Operations was controlled by Mr. Eckel until his death in November 2009, and, since that time, has been controlled by Mr. Lawing. Specifically, Copano Operations charged us, without markup, based upon total monthly expenses incurred by Copano Operations less (i) a fixed allocation to reflect expenses incurred by Copano Operations for the benefit of certain entities and (ii) any costs to be retained by Copano Operations or charged directly to an entity for which Copano Operations performed services.

(6)		Reimbursable costs received from Copano Operations for its use of shared personnel, facilities and equipment. Effective January 1, 2010, we hired the personnel we share with Copano Operations, assumed responsibility for procuring the shared office space, equipment, goods and services and entered into a new agreement under which we provide Copano Operations with access to shared personnel, facilities and equipment in exchange for a monthly charge and rights to use certain assets owned by Copano Operations. This agreement is effective until either party terminates with a 60 day written notice to the other party. This was the only compensation we received from Copano Operations.

(7)		Included in accounts payable on the consolidated balance sheets.

(8)		Costs included in transportation on our consolidated statements of operations.

(9)		Management fees, reimbursable costs and capital project fees received from our unconsolidated affiliates consists of the total compensation paid to us by our unconsolidated affiliates and is included in general and administrative expenses on our consolidated statements of operations.

(10)		Included in accounts receivable on the consolidated balance sheets.

(11)		Revenues included in condensate and other on our consolidated statements of operations.

Director Designation Agreement

Upon the issuance of the Series A preferred units, we entered into a director designation agreement with TPG. Pursuant to the director designation agreement, our Board of Directors expanded its number from seven to eight directors and appointed Michael G. MacDougall, a partner with TPG, to serve as a director until our next annual meeting. We will be obligated to nominate Mr. MacDougall or another designee of TPG for election to our Board of Directors at each annual meeting until: (i) TPG and its affiliates own, in the aggregate, less than 5,163,511 Series A preferred units, together with any common units issued upon conversion of Series A preferred units, or (ii) after July 21, 2013, TPG and its affiliates own, in the aggregate, a number of Series A preferred units, together with any common units issued upon conversion of Series A preferred units that constitutes less than 5% of our common units then outstanding.

For the period from July 1, 2010 through December 31, 2010, certain of our operating subsidiaries incurred $61,000 related to compression services provided by an affiliate of TPG.

Other Transactions

Certain of our operating subsidiaries incurred costs payable to operating subsidiaries of Exterran Holdings, Inc. (“Exterran Holdings”) for the purchase and installation of compressors, compression services and compressor repairs totaling $6,108,000, $3,935,000 and $5,824,000, respectively, for the years ended December 31, 2010, 2009 and 2008. Ernie L. Danner, a member of our Board of Directors, serves on the Board of Directors of Exterran Holdings and as its President and Chief Executive Officer.

F-38

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


Note 7 —	Related Party Transactions (Continued)

During 2010, we purchased approximately 20,000 feet of 24-inch pipe from Fort Union for use in our Texas operations for a purchase price of $810,000.

Our management believes that the terms and provisions of our related party agreements are fair to us; however, we cannot be certain that such agreements and services have terms as favorable to us as we could obtain from unaffiliated third parties.


Note 8 —	Customer Information

The following tables summarize our significant customer information for the period indicated.

Percentage of Revenue⁽¹⁾


			Year Ended December 31,
Customer	Segment		2010			2009			2008

ONEOK Energy Services		Oklahoma		16	%		16	%		16	%
ONEOK Hydrocarbon		Texas and Oklahoma		20	%		17	%		13	%
DCP Midstream		Texas and Oklahoma		12	%		12	%		(1	)
Enterprise Products Partners		Texas		(1	)		(1	)		14	%

Percentage of Cost of Goods Sold⁽¹⁾


			Year Ended December 31,
Producer	Segment		2010			2009			2008

New Dominion LLC		Oklahoma		17	%		16	%		13	%
Equal Energy		Oklahoma		12	%		12	%		(1	)

Percentage of Accounts Receivable⁽¹⁾


			Year Ended December 31,
Customer or Counterparty	Segment		2010			2009			2008

ONEOK Energy Services, L.P.		Oklahoma		15	%		17	%		15	%
ONEOK Hydrocarbon, L.P.		Oklahoma		19	%		21	%		(1	)
DCP Midstream, L.L.C.		Texas and Oklahoma		(1	)		20	%		(1	)
Kinder Morgan		Texas		(1	)		(1	)		11	%
The Goldman Sachs Group, Inc.		Texas		(1	)		(1	)		10	%


(1)		Percentages are not provided for periods for which the customer or producer is less than 10% of our consolidated revenue.


Note 9 —	Financial Instruments

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

F-39

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


Note 9 —	Financial Instruments (Continued)

Commodity Risk Hedging Program

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing or conditioning at our processing plants or third-party processing plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) the cost of transporting and fractionating NGLs. In order to manage the risks associated with natural gas and NGL prices, we engage in risk management activities that take the form of commodity derivative instruments. These activities are governed by our risk management policy, which, subject to certain limitations, allows our management to purchase options and enter into swaps for crude oil, NGLs and natural gas in order to reduce our exposure to a substantial adverse change in the prices of those commodities. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

Our Risk Management Committee monitors and ensures compliance with the risk management policy and consists of senior level executives in the operations, finance and legal departments. The Audit Committee of our Board of Directors monitors the implementation of the policy and we have engaged an independent firm to monitor compliance with our risk management policy on a monthly basis. The risk management policy provides that any derivative transactions must be executed by our Chief Financial Officer or his designee and must be authorized in advance of execution by our Chief Executive Officer. The policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

Financial instruments that we acquire pursuant to our risk management policy are generally designated as cash flow hedges under ASC 815 and are recorded on our consolidated balance sheets at fair value. For derivatives designated as cash flow hedges, we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and reclassify them to revenue within the consolidated statements of operations as the underlying transactions impact earnings. For derivatives not designated as cash flow hedges, we recognize changes in fair value as a gain or loss in our consolidated statements of operations. These financial instruments serve the same risk management purpose whether designated as a cash flow hedge or not.

We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in hedging the variability of forecasted cash flows of underlying hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying hedged item or it becomes probable that the original forecasted transaction will not occur, we discontinue hedge accounting and subsequent changes in the derivative fair value are immediately recognized as a gain or loss (increase or decrease in revenue) in our consolidated statements of operations.

During the years ended December 31, 2010, 2009 and 2008, we reclassified into earnings a gain/(loss) of $0, $1,458,000 and $(407,000), respectively, as a result of the discontinuance of cash flow hedge accounting for certain unwound derivatives.

F-40

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


Note 9 —	Financial Instruments (Continued)

As of December 31, 2010, we estimated that $23,627,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as a result of monthly physical settlements of crude oil, NGLs and natural gas.

At December 31, 2010, the notional volumes of our commodity positions were:


Commodity	Instrument		Unit		2011		2012		2013

Natural gas		Calls		MMBtu/d		10,000		—		—
Natural gas		Call Spreads		MMBtu/d		7,100		—		—
Natural gas		Swaps		MMBtu/d		10,000		—		—
NGL		Puts		Bbl/d		7,950		3,500		—
NGL		Swaps		Bbl/d		1,500		—		—
Crude oil		Puts		Bbl/d		2,700		1,500		400

At December 31, 2009, the notional volumes of our commodity positions were:


Commodity	Instrument		Unit		2010		2011		2012

Natural gas		Calls		MMBtu/d		10,000		10,000		—
Natural gas		Call Spreads		MMBtu/d		7,100		7,100		—
Natural gas		Swaps		MMBtu/d		10,000		—		—
NGL		Puts		Bbl/d		4,600		6,650		—
NGL		Put Spreads		Bbl/d		3,000		—		—
NGL		Swaps		Bbl/d		1,500		1,500		—
Crude oil		Puts		Bbl/d		1,400		2,500		300
Crude oil		Put Spreads		Bbl/d		1,400		—		—

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable rate borrowings under our Credit Facility. We manage a portion of our interest rate exposure using interest rate swaps, which allow us to convert a portion of our variable rate debt into fixed rate debt. As of December 31, 2010, we hold a notional amount of $95.0 million in interest rate swaps with a weighted average fixed rate of 4.30% that mature in October 2012. As of December 31, 2010, our interest rate swaps are not designated as cash flow hedges.

For the years ended December 31, 2010, 2009 and 2008, interest and other financing costs on the consolidated statements of operations include unrealized mark-to-market gains/(losses) of $1,567,000, $2,748,000 and $(10,009,000), respectively, on undesignated interest rate swaps and ineffectiveness on designated interest rate swaps of $0, $0 and $17,000, respectively.

As of December 31, 2010, we estimate that $317,000 of OCI will be reclassified as an decrease to earnings in the next 12 months as the underlying instruments expire.

ASC 820 “Fair Value Measurement” and ASC 815 “Disclosures about Derivative Instruments and Hedging Activities”

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while

F-41

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


Note 9 —	Financial Instruments (Continued)

unobservable inputs reflect our market assumptions. The three levels of the fair value hierarchy established by ASC 820 are as follows:


	•	Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

	•	Level 2 — Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and

	•	Level 3 — Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

At each balance sheet date, we perform an analysis of all instruments subject to ASC 820 and include in Level 3 all of those for which fair value is based on significant unobservable inputs.

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009. As required by ASC 820, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement with the fair value hierarchy levels.

Fair Value Measurements on Hedging Instruments^(a)


	December 31, 2010
	Level 1		Level 2			Level 3		Total
	(In thousands)

Assets:
Natural Gas:
Short-term — Designated^(b)	$	—	$	—		$	87	$	87
Natural Gas Liquids:
Short-term — Designated^(b)		—		—			6,812		6,812
Short-term — Not designated^(b)		—		—			14		14
Long-term — Designated^(c)		—		—			6,391		6,391
Crude Oil:
Short-term — Designated^(b)		—		—			904		904
Short-term — Not designated^(b)		—		—			19		19
Long-term — Designated^(c)		—		—			5,552		5,552

Total	$	—	$	—		$	19,779	$	19,779

Liabilities:
Natural Gas:
Short-term — Not designated^(d)	$	—	$	82		$	—	$	82
Natural Gas Liquids:
Short-term — Designated^(d)		—		—			4,867		4,867
Interest Rate:
Short-term — Not designated^(d)		—		4,408			—		4,408
Long-term — Not designated^(e)		—		2,469			—		2,469

Total	$	—	$	6,959		$	4,867	$	11,826

Total designated assets	$	—	$	—		$	14,879	$	14,879

Total not designated (liabilities)/assets	$	—	$	(6,959	)	$	33	$	(6,926	)

F-42

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


Note 9 —	Financial Instruments (Continued)


(a)		Instruments re-measured on a recurring basis.

(b)		Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”

(c)		Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”

(d)		Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”

(e)		Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”

Fair Value Measurements on Hedging Instruments^(a)


	December 31, 2009
	Level 1		Level 2			Level 3		Total
	(In thousands)

Assets
Commodity derivatives:
Short-term — Designated^(b)	$	—	$	—		$	36,588	$	36,588
Short-term — Not designated^(b)		—		27			—		27
Long-term — Designated^(c)		—		—			14,805		14,805
Long-term — Not designated^(c)		—		—			576		576

Total	$	—	$	27		$	51,969	$	51,996

Liabilities
Commodity derivatives:
Short-term — Designated^(d)	$	—	$	—		$	4,763	$	4,763
Long-term — Designated^(e)		—		—			4,600		4,600
Interest rate derivatives:
Short-term — Not designated^(d)		—		4,909			—		4,909
Long-term — Not designated^(e)		—		3,238			—		3,238

Total	$	—	$	8,147		$	9,363	$	17,510

Total designated assets	$	—	$	—		$	42,030	$	42,030

Total not designated (liabilities)/assets	$	—	$	(8,120	)	$	576	$	(7,544	)


(a)		Instruments re-measured on a recurring basis.

(b)		Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”

(c)		Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”

(d)		Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”

(e)		Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”

We use the income approach incorporating market-based inputs in determining fair value for our derivative contracts.

Valuation of our Level 2 derivative contracts are based on observable market prices (3-month LIBOR interest rate curves or CenterPoint East and Houston Ship Channel market curves) incorporating discount rates and credit risk.

F-43

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


Note 9 —	Financial Instruments (Continued)

Valuation of our Level 3 derivative contracts incorporates the use of valuation models using significant unobservable inputs. To the extent certain model inputs are observable (prices of WTI Crude, Mt. Belvieu NGLs and Houston Ship Channel natural gas), we include observable market price and volatility data as inputs to our valuation model in addition to incorporating discount rates and credit risk. For those input parameters that are not readily available (implied volatilities for Mt. Belvieu NGL prices or prices for illiquid periods of price curves), the modeling methodology incorporates available market information to generate these inputs through techniques such as regression based extrapolation.

The following tables provide a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy:


	Year Ended December 31, 2010
	Natural			Natural Gas
	Gas			Liquids			Crude Oil			Total
	(In thousands)

Asset balance, beginning of year	$	2,752		$	15,641		$	24,213		$	42,606
Total gains or losses:
Non-cash amortization of option premium		(5,906	)		(16,476	)		(9,996	)		(32,378	)
Other amounts included in earnings		—			14,172			18,948			33,120
Included in accumulated other comprehensive loss		3,241			(3,128	)		(14,763	)		(14,650	)
Purchases		—			12,089			7,721			19,810
Settlements		—			(13,949	)		(19,647	)		(33,596	)

Asset balance, end of year	$	87		$	8,349		$	6,476		$	14,912

Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the year	$	—		$	(145	)	$	162		$	17


	Year Ended
	December 31, 2009
	(In thousands)

Asset balance, beginning of year	$	152,677
Total gains or losses:
Non-cash amortization of option premium		(36,950	)
Other amounts included in earnings		72,669
Included in accumulated other comprehensive loss		(84,021	)
Purchases		6,940
Settlements		(68,709	)

Asset balance, end of year	$	42,606

Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the year	$	4,653

Unrealized and realized gains and losses for Level 3 recurring items recorded in earnings are included in revenue on the consolidated statements of operations. The effective portion of unrealized gains and losses relating to cash flow hedges are included in accumulated other comprehensive loss on the consolidated balance sheets and consolidated statements of members’ capital and comprehensive loss.

F-44

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


Note 9 —	Financial Instruments (Continued)

Transfers in and/or out of Level 2 or Level 3 represent existing assets or liabilities where inputs to the valuation became less observable or assets and liabilities that were previously classified as a lower level for which the lowest significant input became observable during the period. There were no transfers in or out of Level 2 or Level 3 during the periods presented.

We have not entered into any derivative transactions containing credit risk related contingent features as of December 31, 2010.

The following table presents derivatives that are designated as cash flow hedges:


The Effect of Derivative Instruments on the Statements of Operations
							Amount of Gain (Loss)
				Amount of Gain (Loss)			Recognized in Income
	Amount of Gain (Loss)			Reclassified from			on Derivative
Derivatives Designated	Recognized in OCI on			Accumulated OCI into			(Ineffective Portion and
as Cash Flow Hedges	Derivatives (Effective			Income (Effective			Amount Excluded from			Statements of
Under ASC 815	Portion)			Portion)			Effectiveness Testing)			Operations Location
(In thousands)

*Year ended December 31, 2010*
Natural gas	$	(2,665	)	$	(5,906	)	$	—		Natural gas sales
Natural gas liquids		(4,095	)		(967	)		(131	)	Natural gas liquids sales
Crude oil		(4,742	)		10,022			(402	)	Condensate and other
Interest rate swaps		—			(478	)		—		Interest and other financing costs

Total	$	(11,502	)	$	2,671		$	(533	)

*Year ended December 31, 2009*
Natural gas	$	3,637		$	(3,401	)	$	—		Natural gas sales
Natural gas liquids		26,123			31,204			(122	)	Natural gas liquids sales
Crude oil		12,365			14,093			(416	)	Condensate and other
Interest rate swaps		(515	)		304			—		Interest and other financing costs

Total	$	41,610		$	42,200		$	(538	)

F-45

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


Note 9 —	Financial Instruments (Continued)

The following table presents derivatives that are not designated as cash flow hedges:


The Effect of Derivative Instruments on the Statements of Operations
	Amount of Gain (Loss)
Derivatives Not Designated as Hedging	Recognized in Income on
Instruments Under ASC 815	Derivative			Statements of Operations Location
(In thousands)

*Year ended December 31, 2010*
Natural gas	$	(98	)	Natural gas sales
Natural gas liquids		356		Natural gas liquids sales
Crude oil		(305	)	Condensate and other
Interest rate swaps		(3,073	)	Interest and other financing costs

Total	$	(3,120	)


*Year ended December 31, 2009*
Natural gas	$	27		Natural gas sales
Natural gas liquids		4,643		Natural gas liquids sales
Interest rate swaps		2,748		Interest and other financing costs

Total	$	7,418

Other Fair-Value Measurements

We recorded a $25,000,000 impairment with respect to our equity interest in Bighorn during the three months ended June 30, 2010. The valuation of this investment required the use of significant unobservable inputs (Level 3). Our probability-weighted discounted cash flow analysis included the following input parameters that are not readily available: (1) a discount rate reflective of our cost of capital and (2) estimated contract rates, volumes, operating and maintenance costs and capital expenditures. As of June 30, 2010 the fair value and the carrying value of our investment in Bighorn was $351,195,000.


Note 10 —	Fair Value of Financial Instruments

Amounts reflected in our consolidated balance sheets as of December 31, 2010 and 2009 for cash and cash equivalents approximate fair value. The fair value of our Credit Facility has been estimated based on similar debt transactions that occurred during the year ended December 31, 2010. Estimates of the fair value of our Senior Notes are based on market information as of December 31, 2010. A summary of the fair value and carrying value of the financial instruments is shown in the table below.


	December 31,
	2010				2009
	Carrying		Estimated		Carrying		Estimated
	Value		Fair Value		Value		Fair Value
			(In thousands)

Cash and cash equivalents	$	59,930	$	59,930	$	44,692	$	44,692
Credit Facility		10,000		9,873		270,000		260,348
2016 Notes		332,665		341,813		332,665		337,655
2018 Notes		249,525		254,516		249,525		251,936

F-46

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


Note 11 —	Commitments and Contingencies

Commitments

For the years ended December 31, 2010, 2009 and 2008, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $3,859,000, $7,260,000 and $7,420,000, respectively. As of December 31, 2010, commitments under our lease obligations for the next five years are payable as follows: 2011 — $3,170,000; 2012 — $1,179,000; 2013 — $833,000, 2014 — $723,000 and 2015 — $728,000.

We are party to firm transportation agreements with Wyoming Interstate Gas Company (“WIC”), under which we are obligated to pay for transportation capacity whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $9,876,000 in 2011, $9,867,000 in 2012, $8,978,000 in 2013, $5,509,000 in 2014, $4,093,000 in 2015 and $15,111,000 thereafter. The agreements expire on December 31, 2019. All of our obligations under these agreements are offset by capacity release agreements under which third party replacement shippers pay for the right to use our capacity. These capacity release agreements cover 100% of our total WIC capacity and continue through December 31, 2019. We have placed in escrow $1.9 million, classified as escrow cash on the consolidated balance sheets, as credit support for our obligations under the WIC agreements.

Additionally, we have two firm gathering agreements with Fort Union, under which we are obligated to pay for gathering capacity on the Fort Union system whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $5,859,000 for 2011, $7,154,000 for 2012, $7,665,000 for 2013, $7,665,000 for 2014, $7,665,000 for 2015 and $14,700,000 thereafter. These commitments expire on November 30, 2017.

We have fixed-quantity contractual commitments to Targa North Texas LP (“Targa”) in settlement of a dispute regarding what portion, if any, of natural gas we purchase from producers that had been contractually dedicated for resale to Targa. As of December 31, 2010, we had fixed contractual commitments to provide Targa a total of 2.373 billion cubic feet of natural gas for October 1, 2009 through December 31, 2010 and for each of 2011, 2012 and 2013. Under the terms of the agreement, we are obligated to pay annual fees ($1.00 per thousand cubic feet (“Mcf”), $1.10 per Mcf, $1.15 per Mcf and $1.25 per Mcf for 2010, 2011, 2012 and 2013, respectively) to the extent our natural gas deliveries to Targa fall below the committed quantity. As of December 31, 2010, we have accrued $2,137,000 of our obligation.

We entered into a fractionation and product sales agreement with Formosa Hydrocarbons Company, Inc. (“Formosa”) to facilitate deliveries of mixed NGLs to Formosa. Under this agreement, we are obligated to pay approximately $0 for 2011, $0 for 2012, $8,085,000 for 2013, $10,731,000 for 2014, $10,731,000 for 2015 and $77,822,000 thereafter to the extent our mixed NGL deliveries fall below the committed quantity. This commitment expires on November 30, 2025.

Regulatory Compliance

In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management, compliance with existing laws and regulations will not materially affect our financial position, results of operations or cash flows.

Litigation

F-47

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


Note 11 —	Commitments and Contingencies (Continued)

indemnified by CMS Gas Transmission and its parent, CMS Enterprises Company, against any losses that Cantera Gas Company may suffer as a result of these claims.

We may, from time to time, be involved in other litigation and claims arising out of our operations in the normal course of business.


Note 12 —	Supplemental Disclosures to the Statements of Cash Flows


	Year Ended December 31,
	2010		2009		2008
	(In thousands)

Cash payments for interest, net of $3,355,000, $3,362,000 and $3,471,000 capitalized in 2010, 2009 and 2008, respectively	$	49,962	$	53,475	$	49,205
Cash payments for federal and state income taxes	$	655	$	762	$	492
In-kind distributions on Series A preferred unit	$	15,188	$	—	$	—

We incurred a change in liabilities for investing activities that had not been paid as of December 31, 2010, 2009 and 2008 of $2,750,000, $7,980,000 and $6,028,000, respectively. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows. As of December 31, 2010, 2009 and 2008, we accrued $7,999,000, $5,249,000 and $13,229,000, respectively, for capital expenditures that had not been paid and, therefore, these amounts are not included in investing activities for each respective period presented.


Note 13 —	Discontinued Operations

Effective October 1, 2009, we sold our crude oil pipeline and related assets, and as a result, we have classified the results of operations of our crude oil pipeline as “discontinued operations” for 2009 and 2008. In the fourth quarter of 2009, we recognized a gain on the sale of the crude oil pipeline system of approximately $0.9 million. Selected financial data for the crude oil pipeline and related assets are as follows (in thousands):


	Year Ended December 31,
	2009		2008

Crude oil sales	$	62,302	$	174,667
Cost of crude oil purchases		58,935		171,401
Income from discontinued operations before taxes	$	2,292	$	2,291
Income tax expense		—		—

Net income from discontinued operations	$	2,292	$	2,291


Note 14 —	Segment Information

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into the following three segments for both internal and external reporting and analysis:


	•	Texas, which includes midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration, treating, conditioning or processing and marketing. Our Texas segment also provides NGL fractionation and transportation. Our Texas segment includes our equity investments in Webb Duval and Eagle Ford and our Louisiana processing assets, which have limited operations.

F-48

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


Note 14 —	Segment Information (Continued)


	•	Oklahoma, which includes 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 equity investment in Southern Dome and, through September 30, 2009, included a crude oil pipeline.

	•	Rocky Mountains, which includes natural gas gathering and treating and compressor rental services in Wyoming. Our Rocky Mountains segment includes our equity investments in Bighorn and Fort Union.

The amounts indicated below as “Corporate and other” relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

We evaluate segment performance based on segment gross margin before depreciation, amortization and impairment. Operating and maintenance expenses and general and administrative expenses incurred at corporate and other are allocated to Texas, Oklahoma and Rocky Mountains based on expenses directly attributable to each segment or an allocation based on activity, as appropriate. We use the same accounting methods and allocations in the preparation of our segment information as used in our consolidated reporting.

F-49

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


Note 14 —	Segment Information (Continued)

Summarized financial information concerning our reportable segments is shown in the following table (in thousands).


							Rocky			Total			Corporate and
	Texas			Oklahoma^(a)			Mountains			Segments			Other			Consolidated

*Year Ended December 31, 2010:*
Total segment gross margin	$	128,682		$	93,617		$	4,440		$	226,739		$	650		$	227,389
Operations and maintenance expenses		29,236			23,955			296			53,487			—			53,487
Depreciation and amortization		24,696			33,154			3,061			60,911			1,661			62,572
General and administrative expenses		9,966			8,655			1,775			20,396			19,951			40,347
Taxes other than income		2,191			2,503			27			4,721			5			4,726
Equity in loss (earnings) from unconsolidated affiliates		3,139			(2,840	)		20,181			20,480			—			20,480

Operating income (loss)	$	59,454		$	28,190		$	(20,900	)	$	66,744		$	(20,967	)	$	45,777

Natural gas sales	$	188,588		$	197,632		$	1,234		$	387,454		$	(6,001	)	$	381,453
Natural gas liquids sales		256,501			236,781			—			493,282			(2,302	)		490,980
Transportation, compression and processing fees		43,233			7,336			17,829			68,398			—			68,398
Condensate and other		11,253			32,462			1,666			45,381			8,952			54,333

Sales to external customers	$	499,575		$	474,211		$	20,729		$	994,515		$	649		$	995,164

Intersegment sales	$	—		$	—		$	—		$	—		$	—		$	—
Interest and other financing costs	$	—		$	—		$	—		$	—		$	53,605		$	53,605
Segment assets	$	594,528		$	658,729		$	651,096		$	1,904,353		$	2,640		$	1,906,993
*Year Ended December 31, 2009:*
Total segment gross margin	$	103,620		$	76,686		$	3,254		$	183,560		$	35,890		$	219,450
Operations and maintenance expenses		27,960			23,469			48			51,477			—			51,477
Depreciation and amortization		20,868			31,698			2,920			55,486			1,489			56,975
General and administrative expenses		9,453			8,087			2,551			20,091			19,420			39,511
Taxes other than income		1,698			1,998			18			3,714			18			3,732
Equity in loss (earnings) from unconsolidated affiliates		60			(1,768	)		(2,892	)		(4,600	)		—			(4,600	)

Operating income	$	43,581		$	13,202		$	609		$	57,392		$	14,963		$	72,355

Natural gas sales	$	147,218		$	165,524		$	5,181		$	317,923		$	(1,237	)	$	316,686
Natural gas liquids sales		206,485			171,018			—			377,503			29,159			406,662
Transportation, compression and processing fees		28,161			6,774			21,048			55,983			—			55,983
Condensate and other		5,149			26,617			981			32,747			7,968			40,715

Sales to external customers	$	387,013		$	369,933		$	27,210		$	784,156		$	35,890		$	820,046

Intersegment sales	$	966		$	(966	)	$	—		$	—		$	—		$	—
Interest and other financing costs	$	—		$	—		$	—		$	—		$	55,836		$	55,836
Segment assets	$	439,375		$	721,091		$	694,710		$	1,855,176		$	12,236		$	1,867,412
*Year Ended December 31, 2008:*
Total segment gross margin	$	142,723		$	133,112		$	5,877		$	281,712		$	(27,568	)	$	254,144
Operations and maintenance expenses		29,950			23,874			—			53,824			—			53,824
Depreciation, amortization and impairment		15,770			30,360			5,521			51,651			1,265			52,916
General and administrative expenses		9,473			7,832			2,445			19,750			25,821			45,571
Taxes other than income		1,336			1,683			—			3,019			—			3,019
Equity in earnings from unconsolidated affiliates		(888	)		(3,283	)		(2,718	)		(6,889	)		—			(6,889	)

Operating income	$	87,082		$	72,646		$	629		$	160,357		$	(54,654	)	$	105,703

Natural gas sales	$	382,189		$	344,045		$	21,812		$	748,046		$	(788	)	$	747,258
Natural gas liquids sales		345,810			280,046			—			625,856			(27,870	)		597,986
Transportation, compression and processing fees		32,912			2,570			23,524			59,006			—			59,006
Condensate and other		6,931			40,880			1,268			49,079			1,090			50,169

Sales to external customers	$	767,842		$	667,541		$	46,604		$	1,481,987		$	(27,568	)	$	1,454,419

Intersegment sales	$	1,991		$	(1,991	)	$	—		$	—		$	—		$	—
Interest and other financing costs	$	—		$	—		$	—		$	—		$	64,978		$	64,978


(a)		Excludes the results of discontinued operations except for the information related to intersegment sales and interest and other financing costs.

F-50

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


Note 15 —	Quarterly Financial Data (Unaudited)


	Year 2010
	Quarter Ended
	March 31			June 30			September 30			December 31			Year
				(In thousands, except per unit information)

Revenue	$	266,666		$	230,051		$	237,704		$	260,743		$	995,164
Operating income (loss)		13,912			(7,691	)		20,546			19,010			45,777
Net (loss) income		(1,260	)		(21,111	)		7,298			6,392			(8,681	)
Basic net loss per common unit		(0.02	)		(0.32	)		(0.00	)		(0.02	)		(0.37	)
Diluted net loss per common unit		(0.02	)		(0.32	)		(0.00	)		(0.02	)		(0.37	)


	Year 2009
	Quarter Ended
	March 31		June 30		September 30		December 31		Year
			(In thousands, except per unit information)

Revenue	$	201,078	$	180,183	$	189,531	$	249,254	$	820,046
Operating income		15,971		18,033		18,146		20,205		72,355
Net income		5,905		6,038		3,729		7,486		23,158
Discontinued operations, net of tax		561		570		262		899		2,292
Basic net income per common unit		0.11		0.11		0.07		0.14		0.43
Diluted net income per common unit		0.10		0.10		0.06		0.13		0.40

F-51

INDEPENDENT AUDITORS’ REPORT

To the Operating Member of Bighorn Gas Gathering, L.L.C.:

We have audited the accompanying balance sheets of Bighorn Gas Gathering, L.L.C. (the “Company”) as of December 31, 2010 and 2009, and the related statements of operations, members’ equity and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 25, 2011

F-52

BIGHORN GAS GATHERING, L.L.C.

STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2010			2009			2008

Cash flows from operating activities:
Net income	$	14,657,702		$	14,241,077		$	16,337,460
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and abandonment		5,320,153			6,210,800			5,358,264
Accretion expense		30,880			21,644			19,677
Provision for doubtful accounts		(40,575	)		1,418,008			—
Gain on disposal of assets		(7,500	)		—			—
Changes in assets and liabilities:
Accounts receivable		279,785			108,913			(1,038,052	)
Prepaid expenses and other		(16,421	)		196,655			(83,541	)
Accounts payable		(474,325	)		(1,546,997	)		1,435,400
Accrued liabilities		68,536			(371,301	)		356,022

Net cash provided by operating activities		19,818,235			20,278,799			22,385,230

Cash flows from investing activities:
Additions to property and equipment		(1,039,454	)		(5,597,786	)		(5,383,494	)
Additions to intangible assets		(525,793	)		(291,374	)		(147,850	)
Proceeds from sale of assets		7,500			—			—

Net cash used in investing activities		(1,557,747	)		(5,889,160	)		(5,531,344	)

Cash flows from financing activities:
Priority distributions to members		(989,885	)		(1,431,833	)		(1,901,500	)
Distributions to members		(20,000,000	)		(21,200,000	)		(18,700,000	)
Equity contributions from members		1,339,382			5,729,516			6,848,711

Net cash used in financing activities		(19,650,503	)		(16,902,317	)		(13,752,789	)

Net (decrease) increase in cash and cash equivalents		(1,390,015	)		(2,512,678	)		3,101,097
Cash and cash equivalents, beginning of year		4,248,715			6,761,393			3,660,296

Cash and cash equivalents, end of year	$	2,858,700		$	4,248,715		$	6,761,393

Supplemental disclosure to the Statements of Cash Flows — Accrued capital expenditures	$	12,542		$	173,517		$	163,236

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

F-55

BIGHORN GAS GATHERING, L.L.C.

STATEMENTS OF MEMBERS’ EQUITY


	Common Member Interests
	Copano						Crestone
	Pipelines/Rocky			Crestone Energy			Gathering
	Mountains, L.L.C.			Ventures, L.L.C.			Services, L.L.C.			Total

Balance at December 31, 2007	$	49,966,002		$	38,209,291		$	9,797,259		$	97,972,552
Contributions		6,586,200			209,325			53,186			6,848,711
Allocation of 2008 contributions		(3,093,358	)		2,461,678			631,680			—
Distributions		(11,438,500	)		(7,293,000	)		(1,870,000	)		(20,601,500	)
Net income		9,263,840			5,630,023			1,443,597			16,337,460

Balance at December 31, 2008		51,284,184			39,217,317			10,055,722			100,557,223
Contributions		2,707,044			2,417,979			604,493			5,729,516
Allocation of 2009 contributions		215,009			(183,467	)		(31,542	)		—
Distributions		(12,243,833	)		(8,268,000	)		(2,120,000	)		(22,631,833	)
Net income		7,964,547			4,995,606			1,280,924			14,241,077

Balance at December 31, 2009		49,926,951			38,179,435			9,789,597			97,895,983
Contributions		847,730			393,322			98,330			1,339,382
Allocation of 2010 contributions		(164,645	)		129,035			35,610			—
Distributions		(11,189,885	)		(7,800,000	)		(2,000,000	)		(20,989,885	)
Net income		7,960,472			5,330,449			1,366,781			14,657,702

Balance at December 31, 2010	$	47,380,623		$	36,232,241		$	9,290,318		$	92,903,182

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

F-56

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

Bighorn Gas Gathering, L.L.C. (the “Company”) is a Delaware limited liability company. The Company was formed in 1999 to construct and operate natural gas gathering lines and related facilities in Wyoming’s Powder River Basin. As of December 31, 2010 and 2009, the members’ common equity interests were owned by the following:


Copano Pipelines/Rocky Mountains, LLC (“Copano”)	51	%
Crestone Energy Ventures, L.L.C. (“Crestone Energy”)	39
Crestone Gathering Services, L.L.C. (“Crestone Gathering”)	10

	100	%

Contributions from the Company’s common members may be required from time to time and are generally required from each member in proportion to their respective ownership percentage. In addition, members may propose capital additions to the Company’s gathering and transportation system. In the event that all members do not consent, consenting members may make capital contributions to the Company, which would be used to fund the prospective capital addition. Such contributions are immediately reallocated to the equity accounts of each member in proportion to their respective ownership interests. Consenting members are entitled to a priority distribution of up to 140% of the amount of capital contributed by such consenting members, as discussed below. Members’ liabilities are limited to the amount of capital contributed.

For the year ended December 31, 2010, common members contributed $1,339,382, including $335,998 from Copano related to nonconsent capital projects. The $335,998 of additional capital was reallocated to the remaining common members resulting in a $164,639 decrease in Copano’s member interest and a corresponding increase in the remaining members’ interests.

For the year ended December 31, 2009, common members contributed $5,729,516, including $1,129,030 from Copano related to nonconsent capital projects, of which $553,225 was allocated to the remaining common members. During the year ended December 31, 2009, the members agreed that a capital project with respect to which Copano had made nonconsent capital contributions would be converted to a consent project. As a result of this change, the remaining common members made a catch-up contribution in the amount of $1,227,964 of which $626,262 was allocated to Copano’s common member interest. Also during the year ended December 31, 2009, the remaining common members remitted contributions of $278,378 of which $141,973 was allocated to Copano, related to 2008 capital requests. The net effect of the reallocation of capital contributions was an increase in Copano’s common member interest and a decrease in the remaining members’ interests in the amount of $215,009.

For the year ended December 31, 2008, common members contributed $6,848,711, including $6,208,747 from Copano related to nonconsent capital projects. The $6,208,747 of additional capital was reallocated to common members, resulting in a $3,093,358 decrease in Copano’s common member interest and a corresponding increase in the remaining members’ interests.

Priority distributions related to net recovery from nonconsent capital projects are made in priority to common distributions. Once 140% of the capital contributed by consenting members has been distributed to the consenting members, net revenue from nonconsent projects is distributable as common distributions. Common member distributions are made using net cash flows from the Company’s operations, as defined in the member agreement, in proportion to the common members’ respective ownership interests. For the year ended December 31, 2010, distributions to common members totaled $20,989,885, including priority distributions to Copano of $989,885. For the year ended December 31, 2009, distributions to common members totaled $22,631,833, including priority distributions to Copano of $1,431,833. For the year ended December 31, 2008, distributions to common members totaled $20,601,500, including priority distributions to Copano of $1,901,500. As noted above, net revenue from nonconsent capital projects is attributable entirely to consenting members up to 140% of the contributed capital. Allocation of the Company’s net income to each member’s capital account is computed by combining (a) the

F-57

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Note 1 — Organization and Basis of Presentation (Continued)

proportion of the member’s respective ownership percentage multiplied by the Company’s net income and (b) the reallocation of the excess distribution related to non-consent projects.


Note 2 —	Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Gas Gathering Operations

The Company’s revenue is derived from fees collected for gathering natural gas. Revenue is recognized once the Company can conclude it has evidence of an arrangement, the fees are fixed or determinable, collectability is probable and delivery has occurred. The Company typically enters into long-term contracts that provide for per unit gathering fees. Fees are determined on a monthly basis based upon actual volumes and are recognized when the gas enters the Bighorn system. The Company assesses collectability at the inception of an arrangement based upon credit ratings and prior collections history.

Cash and Cash Equivalents

The Company considers all highly liquid cash investments with original maturities of three months or less when purchased to be cash equivalents.

Imbalances

Imbalances result when the Company’s customers either over or under-deliver natural gas to the Company’s system. In general, over or under-delivery into the Company’s system is offset by the Company’s equivalent over or under-delivery at the delivery points into the Fort Union gathering system which are then cashed out. Accordingly, at December 31, 2010 and 2009, the Company had no material gas imbalances.

Property and Equipment

Property and equipment are recorded at cost. Repairs and maintenance are charged to expense as incurred. Expenditures that extend the useful lives of assets are capitalized. The historical costs and related accumulated depreciation of assets retired or otherwise disposed of are written off and any resulting loss on the retirement is reflected in the current period deprecation expense. The gain or loss on sale of an asset is reflected in general and administrative expense in the period in which the asset was sold. Depreciation is provided on a straight-line basis over the estimated useful life for each asset.

F-58

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Property and equipment consists of the following:


			December 31,
	Useful Lives		2010			2009

Vehicles		3 years	$	1,026,729		$	1,108,673
Computer and communication equipment		5 years		626,076			545,966
Construction in progress		N/A		84,793			93,749
Gathering lines and related equipment		4-30 years		121,751,978			121,552,679

				123,489,576			123,301,067
Less accumulated depreciation				(37,094,241	)		(32,694,444	)

Property and equipment, net			$	86,395,335		$	90,606,623

The Company’s policy is to capitalize major overhauls of compression equipment, the costs of which are included in gathering lines and related equipment and depreciated over a four-year period until the next expected overhaul. If the Company determines an asset will cease to be used prior to the end of its previously estimated useful life, that asset will be abandoned and depreciation estimates will be revised. For the years ended December 31, 2010, 2009 and 2008, the Company recorded abandonment charges in the amounts of $0, $1,029,394 and $0, respectively. Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was $5,089,767, $4,956,534 and $5,080,969, respectively.

Other Assets

Our other assets consist of rights-of-way agreements. The Company amortizes existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable. Initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. Amortization expense was $230,386, $224,872 and $277,295 for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated aggregate amortization expense remaining for each of the five succeeding fiscal years is approximately: $245,000 for 2011, $244,000 for 2012, $144,000 for 2013, $127,000 for 2014, $126,000 for 2015 and $1,473,000 thereafter. Intangible assets consisted of the following (in thousands):


	December 31,
	2010			2009

Rights-of-way, at cost	$	3,437,531		$	2,986,178
Less accumulated amortization for rights-of-way		(1,078,743	)		(922,797	)

Rights-of-way, net	$	2,358,788		$	2,063,381

For the years ended December 31, 2010, 2009 and 2008, the weighted average amortization period for rights-of-way agreements was 16, 20 and 15 years, respectively.

Impairment of Long-Lived Assets

In accordance with Accounting Standards Codification 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use

F-59

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of the Company’s long-lived assets has occurred, the Company must estimate the undiscounted cash flows attributable to the asset or asset group. The cash flows estimate is based on assumptions regarding the asset, including future commodity prices and estimated future natural gas production in the region (which is dependent in part on commodity prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:


	•	changes in general economic conditions in which the Company’s assets are located;

	•	the availability and prices of natural gas supply;

	•	improvements in exploration and production technology;

	•	the finding and development cost for producers to exploit reserves in a particular area;

	•	the Company’s ability to negotiate favorable agreements with producers and customers;

	•	the Company’s dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

	•	competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect the Company’s cash flows, which could require the Company to record an impairment of an asset. No such impairment losses were recorded for the years ended December 31, 2010, 2009 or 2008.

Asset Retirement Obligations

The following table presents information regarding the Company’s AROs:


ARO liability balance, December 31, 2008	$	216,444
AROs incurred in 2009		—
Accretion for conditional obligations		21,644

ARO liability balance, December 31, 2009		238,088
AROs incurred in 2010		—
Accretion for conditional obligations		30,880

ARO liability balance, December 31, 2010	$	268,968

F-60

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, accounts receivable, prepaid expenses, accounts payable and accrued liabilities. The carrying amounts of financial instruments approximate fair value due to their short maturities.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable at December 31, 2010 and 2009 results from gas gathering fees earned from other companies in the oil and gas industry. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. However, the Company performs credit evaluations on all its customers to minimize exposure to credit risk. During the years ended December 31, 2010, 2009 and 2008, the Company recorded an allowance for doubtful accounts of $0, $1,418,008 and $0, respectively.

As of December 31, 2010, trade accounts receivable includes a receivable from one customer representing 65% of total accounts receivable, and as of December 31, 2009, trade accounts receivable includes receivables from three customers representing 38%, 34%, and 12% of total accounts receivable.

For the year ended December 31, 2010, revenue includes gathering fees received from two customers representing 73% and 12% of total revenue, for the year ended December 31, 2009, revenue includes gathering fees received from two customers representing 71% and 15% of total revenue and for the year ended December 31, 2008, revenue includes gathering fees received from two customers representing 68% and 18% of total revenue.

Income Taxes

Due to the Company’s limited liability status, the income tax consequences of the Company pass through to the individual members. Accordingly, no provision has been made for federal or state income taxes.

Subsequent Events

The Company’s management believes that the disclosures are adequate to make the information presented not misleading. In the preparation of these financial statements, the Company’s management evaluated subsequent events through February 25, 2011, the issuance date of the financial statements.


Note 3 —	Lease Commitments

The Company leases certain equipment, including equipment from related parties (see Note 4), for use on its gathering system under month-to-month and long term operating leases. For the years ended December 31, 2010, 2009 and 2008, rent expense totaled $3,530,611, $4,541,653 and $4,878,314, respectively. As of December 31, 2010, commitments under the Company’s operating leases are payable as follows: 2011 — $653,701; 2012 and thereafter — $0. At the end of the current lease terms, substantially all leases convert to month-to-month leases.


Note 4 —	Related-Party Transactions

During the years ended December 31, 2010, 2009 and 2008, gathering services provided to Copano accounted for approximately 0%, 1% and 2%, respectively, of the Company’s total revenue. During the years ended December 31, 2010, 2009 and 2008, gathering services provided to Crestone Energy accounted for approximately 1%, 1% and 0%, respectively, of the Company’s total revenue.

F-61

BIGHORN GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 4 —	Related-Party Transactions (Continued)

As of December 31, 2010 and 2009, accounts receivable includes $0 and $22,781, respectively, for gathering services provided to Copano. As of December 31, 2010 and 2009, accounts receivable include $29,265 and $47,693, respectively, for gathering services provided to Crestone Energy.

Beginning May 1, 2009, the Company began leasing compressors for use on its gathering system from Copano Field Facilities/Rocky Mountains, LLC, an indirect wholly-owned subsidiary of Copano. During the years ended December 31, 2010 and 2009, the Company reflected in operating and maintenance expenses $1,766,156 and $980,901, respectively, related to these leases. As of December 31, 2010 and 2009, there were no amounts due to Copano Field Facilities/Rocky Mountains, LLC. Management believes that the terms of these transactions are fair to the Company; however, it cannot be certain that such transactions have terms as favorable to the Company as could have been achieved with an unaffiliated entity.

The Company pays Copano management fees related to the operation and administration of the Company’s gathering system. For the years ended December 31, 2010, 2009 and 2008, the Company reflected in operating and maintenance expenses and general and administrative expenses management fees totaling $555,660, $356,580 and $287,316, respectively, and reimbursable costs totaling $2,473,070, $3,120,890 and $252,018, respectively.

As of December 31, 2010 and 2009, the Company had accounts payable to Copano of $43,854 and $490,206, respectively, and accounts receivable from Copano of $3,330 and $0, respectively, related to management fees and reimbursements of expenses.


Note 5 —	Commitments and Contingencies

Although the Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Company is not currently a party to any material legal proceedings. In addition, management of the Company is not aware of any material legal or governmental proceedings against the Company, or contemplated to be brought against the Company, under the various environmental protection statutes to which the Company is subject, that would have a significant adverse effect on the Company’s financial position, results of operations or cash flows.

F-62

INDEPENDENT AUDITORS’ REPORT

To the Operating Member of Fort Union Gas Gathering, L.L.C.:

We have audited the accompanying balance sheets of Fort Union Gas Gathering, L.L.C. (the “Company”) as of December 31, 2010 and 2009, and the related statements of operations, members’ equity and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

/s/ Deloitte & Touche LLP

Houston, Texas

February 25, 2011

F-63

FORT UNION GAS GATHERING, L.L.C.

BALANCE SHEETS


	December 31,
	2010		2009

ASSETS
Current assets:
Cash and cash equivalents	$	8,784,850	$	7,746,143
Accounts receivable:
Trade		1,216,693		406,391
Related parties		5,726,927		4,186,270

Total current assets		15,728,470		12,338,804
Property and equipment, net		202,163,789		209,890,618
Other assets, net		2,260,261		2,525,086

Total assets	$	220,152,520	$	224,754,508


LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	28,829	$	14,708
Related parties		875,027		3,960,885
Current portion of long-term debt		13,752,000		13,752,000
Interest rate swap agreements		2,079,619		2,363,266
Accrued liabilities		3,208,668		1,055,006

Total current liabilities		19,944,143		21,145,865

Long-term debt		72,198,000		85,950,000
Interest rate swap agreements		1,885,154		1,727,032
Asset retirement obligations		119,514		—
Commitments and contingencies (Note 7)
Members’ equity		126,005,709		115,931,611

Total liabilities and members’ equity	$	220,152,520	$	224,754,508

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

F-64

FORT UNION GAS GATHERING, L.L.C.

STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2010			2009			2008

Cash flow from operating activities:
Net income	$	39,483,212		$	44,466,650		$	33,487,593
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,739,030			8,180,001			6,168,689
Amortization of debt issue costs		179,721			346,066			450,068
Net change in interest rate swaps		(125,525	)		(1,304,322	)		5,640,714
Accretion expense		23,339			—			—
Changes in assets and liabilities:
Accounts receivable		(2,350,959	)		192,227			(849,792	)
Prepaid expenses and other		—			193,262			(98,305	)
Accounts payable		(1,110,826	)		558,530			1,178,277
Accrued liabilities		2,153,662			671,156			(3,939,100	)

Net cash provided by operating activities		45,991,654			53,303,570			42,038,144

Cash flow from investing activities:
Additions to property, plant and equipment		(2,602,024	)		(3,150,160	)		(88,762,219	)
Additions to intangible assets		—			—			(21,829	)
Proceeds from sale of property and equipment		810,191			—			—

Net cash used in investing activities		(1,791,833	)		(3,150,160	)		(88,784,048	)

Cash flow from financing activities:
Proceeds of long-term debt		—			—			31,100,000
Repayments on long-term debt		(13,752,000	)		(17,407,115	)		(12,124,208	)
Distributions to members		(31,500,000	)		(37,050,000	)		(26,200,002	)
Equity contributions from members		2,090,886			2,577,555			54,660,022

Net cash (used in) provided by financing activities		(43,161,114	)		(51,879,560	)		47,435,812

Net increase (decrease) in cash and cash equivalents		1,038,707			(1,726,150	)		689,908
Cash and cash equivalents, beginning of year		7,746,143			9,472,293			8,782,385

Cash and cash equivalents, end of year	$	8,784,850		$	7,746,143		$	9,472,293

Supplemental disclosure to the Statements of Cash Flows —
Cash paid for interest, net of amount capitalized	$	4,127,489		$	3,979,350		$	7,452,140

Accrued capital expenditures	$	—		$	1,960,911		$	—

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

F-66

FORT UNION GAS GATHERING, L.L.C.

STATEMENTS OF MEMBERS’ EQUITY


	Copano									Williams
	Pipelines/Rocky			Crestone Powder			Western Gas			Production RMT
	Mountains, L.L.C.			River L.L.C.			Wyoming L.L.C.			Company L.L.C.			Total

Balance at December 31, 2007	$	16,293,819		$	16,293,819		$	6,514,889		$	4,887,266		$	43,989,793
Contributions		20,246,072			20,246,072			8,095,149			6,072,729			54,660,022
Distributions		(9,704,481	)		(9,704,481	)		(3,880,220	)		(2,910,820	)		(26,200,002	)
Net income		12,403,804			12,403,804			4,959,513			3,720,472			33,487,593

Balance at December 31, 2008		39,239,214			39,239,214			15,689,331			11,769,647			105,937,406
Contributions		954,726			954,726			381,737			286,366			2,577,555
Distributions		(13,723,320	)		(13,723,320	)		(5,487,105	)		(4,116,255	)		(37,050,000	)
Net income		16,470,448			16,470,448			6,585,510			4,940,244			44,466,650

Balance at December 31, 2009		42,941,068			42,941,068			17,169,473			12,880,002			115,931,611
Contributions		774,465			774,465			309,659			232,297			2,090,886
Distributions		(11,667,600	)		(11,667,600	)		(4,665,150	)		(3,499,650	)		(31,500,000	)
Net income		14,624,582			14,624,582			5,847,463			4,386,585			39,483,212

Balance at December 31, 2010	$	46,672,515		$	46,672,515		$	18,661,445		$	13,999,234		$	126,005,709

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

F-67

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS


Note 1 —	Organization and Business

Fort Union Gas Gathering, L.L.C. (the “Company”) is a Delaware limited liability company. The Company was formed in 1999 to construct and operate a natural gas gathering system in Wyoming’s Powder River Basin. The members’ interests of the Company at December 31, 2010 and 2009 are as follows:


Copano Pipelines/Rocky Mountains, LLC (“Copano”)	37.04	%
Crestone Powder River L.L.C. (“Crestone”)	37.04
Western Gas Wyoming, L.L.C. (“Western”)	14.81
Williams Production RMT Company L.L.C. (“Williams”) (formerly Bargath, Inc.)	11.11

	100.00	%

Pursuant to the operating agreement among the members, net income and distributions are allocated among the member interests in proportion to their respective equity interest. Members’ liabilities are limited to the amount of capital contributed.


Note 2 —	Summary of Significant Accounting Policies

Use of Estimates

Revenue Recognition

The Company’s revenue is derived from fees collected for gathering and treating natural gas. Revenue is recognized once the Company can conclude that it has evidence of an arrangement, the fees are fixed or determinable, collectability is probable, and delivery has occurred. The Company typically enters into long-term contracts that provide for per unit gathering and treating fees. Gathering fees are determined on a monthly basis based upon actual volumes. The treating fees associated with the gas are based upon the composition of the natural gas received versus the gas specifications allowed by contract. Gathering and treating fee revenue is recognized once the gas reaches its point of receipt. The Company assesses collectability at the inception of an arrangement based upon credit ratings and prior collections history. In general, the Company conducts business with customers whom the Company has a long collection history. As a result, the Company has not experienced significant credit losses, nor has its revenue recognition been impacted due to assessments of collectability.

Cash and Cash Equivalents

The Company considers all highly-liquid cash investments with maturities of three months or less at the time of purchase to be cash equivalents.

Imbalances

Imbalances represent differences between gas receipts from customers (shippers) and gas deliveries to pipelines. Natural gas imbalances are settled in natural gas volumes, subject to the various contract terms. The Company values gas imbalances at the appropriate market price. The pipelines into which the Company delivers the majority of transported volumes settle all imbalances on a monthly basis. The Company in turn settles all imbalances with shippers on the Company’s system on a monthly basis. At December 31, 2010 the Company had an imbalance receivable of $1,004,736. At December 31, 2009, the Company did not have any material imbalances.

F-68

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Fuel

The Company is entitled to recoup fuel costs from shippers based upon actual fuel used in operations. The Company collects fuel charges based upon estimated fuel costs, which are adjusted periodically to account for differences between estimated fuel charges and actual fuel used. Accumulated differences are recorded as a receivable from or liability to the shippers. The Company records receivables and payables based upon the fair market price of fuel in the month in which the differences were generated. As the fuel rates are adjusted to account for historical differences, the Company reduces the receivable or payable at the current month average price. At December 31, 2010 and 2009, the Company had net fuel payables of $1,907,748 and $452,556, respectively, which are included in accrued liabilities on the accompanying balance sheets.

Property and Equipment

Property and equipment are recorded at cost. Repairs and maintenance are charged to expense as incurred. Expenditures that extend the useful lives of the assets are capitalized. The historical costs and related accumulated depreciation of assets retired or otherwise disposed of are written off and any resulting loss on the retirement is reflected in the current period deprecation expense. The gain or loss on sale of an asset is reflected in general and administrative expense in the period in which the asset was sold. Depreciation is provided on a straight-line basis over the estimated useful life for each asset. Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was $7,653,926, $8,084,892 and $5,619,912, respectively. Property and equipment included the following:


			December 31,
	Useful Lives		2010			2009

Gathering lines and related equipment		30 years	$	238,478,151		$	238,672,852
Computers and communication equipment		3 — 5 years		6,742			6,742
Construction in progress		N/A		—			—

				238,484,893			238,679,594
Less accumulated depreciation				(36,321,104	)		(28,788,976	)

Property and equipment, net			$	202,163,789		$	209,890,618

The Company capitalizes interest on major projects during extended construction time periods. The Company capitalized $337,111, $0 and $3,762,008 of interest related to projects during the years ended December 31, 2010, 2009 and 2008, respectively.

Other Assets

Other assets consist of costs associated with securing debt and rights-of-way agreements.


	December 31,
	2010			2009

Debt issuance costs	$	3,157,794		$	3,157,794
Less accumulated amortization		(2,738,447	)		(2,558,726	)
Rights of way		2,552,126			2,552,126
Less accumulated amortization		(711,212	)		(626,108	)

Other assets — net	$	2,260,261		$	2,525,086

F-69

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

The Company amortizes the cost of securing debt using a method which approximates the effective interest method. During the years ended December 31, 2010, 2009 and 2008, the Company recorded $179,721, $346,066 and $450,068, respectively, of amortization of deferred financing costs as interest expense.

The Company amortizes existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable. Initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. For the years ended December 31, 2010 and 2009, the weighted average amortization period for rights-of-way agreements was 21 and 22 years, respectively. During the years ended December 31, 2010, 2009 and 2008, amortization expense related to rights-of-way agreements was $85,104, $95,109 and $548,777, respectively. Estimated aggregate amortization expense is approximately $85,000 for 2011, $85,000 for 2012, $85,000 for 2013, $85,000 for 2014, $85,000 for 2015 and $1,416,000 thereafter.

Impairment of Long-Lived Assets

In accordance with Accounting Standards Codification (“ASC”) 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.


	•	changes in general economic conditions in which the Company’s assets are located;

	•	the availability and prices of natural gas supply;

	•	improvements in exploration and production technology;

	•	the finding and development cost for producers to exploit reserves in a particular area;

	•	the Company’s ability to negotiate favorable agreements with producers and customers;

	•	the Company’s dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

	•	competition from other midstream service providers, including major energy companies.

F-70

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 2 —	Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result generally from the acquisition, construction, development or normal operation of the asset. When an ARO is incurred, the Company recognizes a liability for the fair value of the ARO and an increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value and recognized as accretion expense each period, and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. The Company recorded a liability of $119,514 as of December 31, 2010 and there was no material liability in previous periods. The Company recorded accretion expense of $23,339 for the year ended December 31, 2010.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, accounts receivable, accounts payable, accrued liabilities, debt, and interest rate swaps. Except for debt, the carrying amounts of financial instruments approximate fair value due to their short maturities. Interest rate swap liabilities are recorded at fair value in the accompanying balance sheets. At December 31, 2010 and 2009, the fair value of the Company’s debt, based on similar debt transactions and market information, was estimated to be $84,823,463 and $96,446,654, respectively.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable at December 31, 2010 and 2009 result from the gathering and treating of gas for other companies in the oil and gas industry. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. However, the Company performs credit evaluations on all its customers to minimize exposure to credit risk. During the years ended December 31, 2010, 2009 and 2008, credit losses were not significant. See Note 6.

Income Taxes

Due to the Company’s limited liability status, the tax consequences of the Company pass through to the individual members. Accordingly, no provision has been made for federal or state income taxes.

Derivative Financial Instruments

In accordance with ASC 815, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted, the Company recognizes derivative financial instruments in the balance sheet as either an asset or liability measured at fair value. Changes in the derivative’s fair value are recognized in current earnings.

Subsequent Events


Note 3 —	New Accounting Pronouncements

Fair Value Measurements

In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value

F-71

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 3 —	New Accounting Pronouncements (Continued)

Measurements,” which updates ASC 820-10 to require new disclosure of amounts transferred in and out of Level 1 and Level 2 of the fair value hierarchy and presentation of a reconciliation of changes in fair value amounts in the Level 3 fair value hierarchy on a gross basis rather than a net basis. Additionally, ASU 2010-06 requires greater disaggregation of the assets and liabilities for which fair value measurements are presented and requires expanded disclosure of the valuation techniques and inputs used for Level 2 and Level 3 fair value measurements. The Company adopted ASU 2010-06 on January 1, 2010.


Note 4 —	Interest Rate Swap Agreements

The Company’s interest rate exposure results from variable rate borrowings under its debt agreements. The Company manages a portion of its interest rate exposure by utilizing interest rate swaps, which allows the Company to convert a portion of variable rate debt into fixed rate debt. At December 31, 2010 and 2009, the Company held notional amounts of $57,000,000 and $66,120,000, respectively, in interest rate swaps. The fixed rates on these agreements range from 4.235% to 4.248% and they mature April 2013.

The fair value of these interest rate swaps is determined based on the amount at which the fixed interest rate differs from the quoted market rate. As of December 31, 2010 and 2009, the fair values of these interest rate swaps were a liability of $3,964,773 and $4,090,298, respectively. Changes in the fair value of unsettled interest rate swaps and realized losses on settled positions are recorded as interest expense. During the years ended December 31, 2010, 2009 and 2008, the Company paid settlements of $2,484,712, $2,030,378 and $948,227, respectively, under these swap agreements.

ASC 820 “Fair Value Measurement” and ASC 815 “Disclosures about Derivative Instruments and Hedging Activities”

The Company recognizes the fair value of its assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect management’s market assumptions. The three levels of the fair value hierarchy established by ASC 820 are as follows:


	•	Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

	•	Level 2 — Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and

	•	Level 3 — Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

At each balance sheet date, the Company performs an analysis of all instruments subject to ASC 820 and includes in Level 3 all of those for which fair value is based on significant unobservable inputs.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010 and 2009. As required by ASC 820, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Level 2 derivative contracts are based on observable market prices (3-month LIBOR interest rate curves) incorporating discount rates and credit risk. Management’s assessment of the significance of a

F-72

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 4 —	Interest Rate Swap Agreements (Continued)

particular input to the fair value measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement with the fair value hierarchy levels.

Fair Value Measurement on Hedging Instruments^(a)


	December 31, 2010								December 31, 2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Liabilities
Interest rate derivatives:
Short-term — Not designated^(b)	$	—	$	2,079,619	$	—	$	2,079,619	$	—	$	2,363,266	$	—	$	2,363,266
Long-term — Not designated^(c)		—		1,885,154		—		1,885,154		—		1,727,032		—		1,727,032

Total	$	—	$	3,964,773	$	—	$	3,964,773	$	—	$	4,090,298	$	—	$	4,090,298

Total designated	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—

Total not designated	$	—	$	3,964,773	$	—	$	3,964,773	$	—	$	4,090,298	$	—	$	4,090,298


(a)		Instruments re-measure on a recurring basis

(b)		Included on the balance sheets as a current liability under the heading of “Interest rate swap agreements”

(c)		Included on the balance sheets as a noncurrent liability under the heading of “Interest rate swap agreements”

The following table presents derivatives that are not designated as cash flow hedges:


The Effect of Derivative Instruments on the Statements of Operations
	Amount of Loss
	Recognized in
Derivatives Not Designated as Hedging	Income on		Statements of
Instruments Under ASC 815	Derivative		Operations Location

*Year ended December 31, 2010*
Interest rate	$	2,359,187		Interest and other financing costs

Total	$	2,359,187

*Year ended December 31, 2009*
Interest rate	$	726,056		Interest and other financing costs

Total	$	726,056


Note 5 —	Debt

Long-term debt consists of the following:


	December 31,
	2010			2009

Term loan, with principal payments and interest due quarterly; interest payable at the prime rate plus 0.5% or LIBOR plus 1.5% (1.79% and 1.74% at December 31, 2010 and 2009, respectively). Balloon payment of $55,068,165 due April 2013.	$	85,950,000		$	99,702,000

		85,950,000			99,702,000
Less current portion of long-term debt		(13,752,000	)		(13,752,000	)

Long-term debt	$	72,198,000		$	85,950,000

F-73

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 5 —	Debt (Continued)

The Company’s debt is secured by its fixed assets. The credit agreement for the Company’s debt includes covenants and restrictions. The Company must maintain a certain debt service ratio and must submit written notice to the banks for distribution to members and reimbursement of administrative and management fees. The Company is in compliance with the financial covenants under the credit agreement as of December 31, 2010.

Future maturities of long-term debt at December 31, 2010 are as follows:


Year Ending December, 31:
2011	$	13,752,000
2012		13,752,000
2013		58,446,000

	$	85,950,000


Note 6 —	Related Party Transactions

As of December 31, 2010, related party accounts receivable include receivables from three members (or their affiliates) representing 51%, 30% and 1%, of total accounts receivable. As of December 31, 2009, related party accounts receivable include receivables from four members (or their affiliates) representing 50%, 34%, 4% and 3% of total accounts receivable. At December 31, 2010 and 2009, accounts receivable includes $5,726,927 and $4,186,270, respectively, due from these members.

Substantially all of the Company’s revenues are from the Company’s members or their affiliates. The portion of revenue that included gathering and treating fees from the members and affiliates is as follows:


	December 31,
	2010			2009			2008

Copano		9	%		13	%		18	%
Crestone		5			13			15
Western		49			35			37
Williams		35			33			28

Total		98	%		94	%		98	%

The Company purchases certain services from Western, Crestone and Copano. These services include operation, management and administrative services related to the gathering system. For the year ended December 31, 2010, the Company incurred $5,209,926 for reimbursement of actual expenses paid by Western, $338,388 for reimbursement of actual expenses paid by Crestone and $891,754 for reimbursement of actual expenses paid by Copano. For the year ended December 31, 2009, the Company incurred $4,896,181 for reimbursement of actual expenses paid by Western, $316,248 for reimbursement of actual expenses paid by Crestone and $1,418,708 for reimbursement of actual expenses paid by Copano. For the year ended December 31, 2008, the Company incurred $3,076,880 for reimbursement of actual expenses paid by Western, $300,900 for reimbursements of actual expenses paid by Crestone and $94,716 for reimbursement of actual expenses paid by Copano.

Accounts payable due to related parties at December 31, 2010 and 2009 include $875,027 and $3,960,885, respectively, due to members for capital expenditures and services rendered.

During the years ended December 31, 2010, 2009 and 2008, the Company reimbursed Western $2,698,199, $3,150,160 and $77,763,804, respectively, for capital expenditures paid by Western on behalf of the Company related to the Company’s pipeline expansion.

F-74

FORT UNION GAS GATHERING, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


Note 6 —	Related Party Transactions (Continued)

During 2010, the Company sold approximately 20,000 feet of 24-inch pipe to a subsidiary of Copano for $810,191.

Management believes that the terms of these transactions are fair to the Company; however, it cannot be certain that such transactions have terms as favorable to the Company as could have been achieved with an unaffiliated entity.


Note 7 —	Commitments and Contingencies

The Company has various operating leases for office facilities and equipment, which all have month-to-month terms. Total rental expense included in operating expense for the years ended December 31, 2010, 2009 and 2008 was $236,316, $71,961 and $9,882, respectively.

F-75


			Page

PART I
	Item 1.	Business		1
	Item 1A.	Risk Factors		26
	Item 1B.	Unresolved Staff Comments		44
	Item 2.	Properties		44
	Item 3.	Legal Proceedings		44

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		45
	Item 6.	Selected Financial Data		47
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		77
	Item 8.	Financial Statements and Supplementary Data		83
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		83
	Item 9A.	Controls and Procedures		83
	Item 9B.	Other Information		87

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		87
	Item 11.	Executive Compensation		87
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		87
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		87
	Item 14.	Principal Accounting Fees and Services		87

PART IV
	Item 15.	Exhibits, Financial Statement Schedules		88

FINANCIAL STATEMENTS
Copano Energy, L.L.C. Index to Financial Statements				F-1
EX-10.4
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


(1)		Average NGL prices are calculated based on our Oklahoma segment weighted-average product mix for the period indicated.


Number			Description

	21	.1	List of Subsidiaries (incorporated by reference to Exhibit 21.1 to Automatic Shelf Registration Statement on Form S-3ASR filed November 3, 2009).
	23	.1*	Consent of Deloitte & Touche LLP.
	31	.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
	31	.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
	32	.1**	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
	32	.2**	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
	101	.CAL*	XBRL Calculation Linkbase Document.
	101	.DEF*	XBRL Definition Linkbase Document.
	101	.INS*	XBRL Instance Document.
	101	.LAB*	XBRL Labels Linkbase Document.
	101	.PRE*	XBRL Presentation Linkbase Document.
	101	.SCH*	XBRL Schema Document.


*		Filed herewith.

**		Furnished herewith.

†		Portions of this Exhibit have been omitted pursuant to a request for confidential treatment.


	Page

Copano Energy, L.L.C. and Subsidiaries Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2010 and 2009		F-3
Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		F-5
Consolidated Statements of Members’ Capital and Comprehensive (Loss) Income for the years ended December 31, 2010, 2009 and 2008		F-6
Notes to Consolidated Financial Statements		F-7
Bighorn Gas Gathering, L.L.C. Financial Statements:
Independent Auditors Report		F-52
Balance Sheets as of December 31, 2010 and 2009		F-53
Statements of Operations for the years ended December 31, 2010, 2009 and 2008		F-54
Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		F-55
Statements of Members’ Capital for the years ended December 31, 2010, 2009 and 2008		F-56
Notes to Financial Statements		F-57
Fort Union Gas Gathering, L.L.C. Financial Statements:
Independent Auditors Report		F-63
Balance Sheets as of December 31, 2010 and 2009		F-64
Statements of Operations for the years ended December 31, 2010, 2009 and 2008		F-65
Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		F-66
Statements of Members’ Capital for the years ended December 31, 2010, 2009 and 2008		F-67
Notes to Financial Statements		F-68