Copano Energy, L.L.C. - 10-K Annual Report

As generally used in the energy industry and in this Annual Report, the following terms have the following meanings:

$/gal:		U.S. dollars per gallon
Bbls:		Barrels
Bbls/d:		Barrels per day
Btu:		British thermal units
Mcf		One thousand cubic feet
Mcf/d		One thousand cubic feet per day
MMBtu:		One million British thermal units
MMcf:		One million cubic feet
MMBtu/d:		One million British thermal units per day
MMcf/d:		One million cubic feet per day
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
throughput:		The volume of product transported or passing through a pipeline, plant, terminal or other facility

Item 1. Business

General

Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities operating under the Copano name since 1992. We completed our initial public offering on November 15, 2004 and our common units are listed on The NASDAQ National Market under the symbol “CPNO.” Our business activities are primarily conducted through wholly owned subsidiaries. References in this Annual Report to “Copano Energy, L.L.C.,” “we,” “our,” “us,” or like terms refer to Copano Energy, L.L.C. and its consolidated subsidiaries.

We are a growth-oriented midstream energy company with networks of natural gas gathering and intrastate transmission pipelines in the South Texas and Texas Gulf Coast regions. Our natural gas processing plant is the second largest in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. Our natural gas pipeline assets consist of approximately 1,366 miles of gas gathering and transmission pipelines, including 144 miles of pipeline owned by a partnership in which we own a 62.5% interest and which we operate. These pipelines collect natural gas from designated points near producing wells and transport these volumes to third-party pipelines, our Houston Central Processing Plant, utilities and industrial consumers.

Our Houston Central Processing Plant is located approximately 100 miles southwest of Houston and has the capacity to process approximately 700 million cubic feet of gas per day, or MMcf/d. Volumes shipped to our processing plant, either on our pipelines or a third-party pipeline, are treated to remove contaminants and conditioned or processed to extract mixed natural gas liquids, or NGLs. Processed or conditioned natural gas is then delivered to third-party pipelines through plant interconnects, while NGLs are fractionated or separated and then sold as component NGL products, including ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. We also own a 104-mile NGL products pipeline extending from the Houston Central Processing Plant to the Houston area.

We have two operating segments: Copano Pipelines, which performs our natural gas gathering and transmission and related operations, and Copano Processing, which performs our natural gas processing, treating and conditioning and related NGL transportation operations. Please read Item 7, “Management’s

Discussion and Analysis of Financial Condition and Results of Operation—Our Results of Operation” and Note 17 to the Consolidated Financial Statements, “Segment Information” contained in Item 8 of this Annual Report for more detailed descriptions of the financial results of our operating segments.

Business Strategy

Our management team is committed to increasing the amount of cash available for distribution by improving the cash flows from our existing assets, pursuing complementary acquisition and expansion opportunities and maintaining an appropriate mix of index-related and fixed-fee margin business to stabilize our cash flow. Key elements of our strategy include the following:

· Increase cash flows from our existing assets. Our pipelines have excess capacity, which provides us with opportunities to increase throughput volume with minimal incremental costs. We intend to increase cash flows from our existing assets by aggressively marketing our services to producers to connect new supplies of natural gas, increase volumes and more fully utilize our capacity.

· Pursue complementary acquisitions, expansion and asset enhancement opportunities. We intend to continue to make complementary acquisitions of midstream assets in our operating areas that provide opportunities to expand either the acquired assets or our existing assets to increase utilization. We pursue acquisitions that we believe will allow us to capitalize on our existing infrastructure, personnel, and producer and customer relationships to provide an integrated package of services. For example, after our acquisition and integration of our Karnes County Gathering System, we acquired the Runge Gathering System and with some modifications and enhancements, attached it to the Karnes County Gathering System. These pipeline acquisitions allowed us to deliver additional natural gas to our Houston Central Processing Plant.

· Exploit the operating flexibility of our assets. Exploiting our ability to condition gas, rather than fully process it, provides us with significant benefits during periods when fully processing natural gas is not economic. We intend to monitor natural gas and NGL prices to quickly switch between processing and conditioning modes at our Houston Central Processing Plant when it is economically appropriate to do so. We will also continue to take advantage of multiple residue outlets at our Houston Central Processing Plant and multiple inlet supply points in our Upper Gulf Coast Region.

· Enter into contracts that provide us with positive operating margins under a variety of market conditions. Because of the significant volatility of natural gas and NGL prices, we attempt to structure our contracts in a manner that allows us to achieve positive gross margins from our contracts in a variety of market conditions. In our processing contracts, we focus on arrangements pursuant to which we are paid a fee to condition natural gas when processing is economically unattractive. In our contracts with producers, we focus on arrangements pursuant to which the fee received for the services we deliver is sufficient to provide us with positive operating margins irrespective of NGL prices. Collectively, this strategy should provide us with a more predictable revenue stream.

· Expand our geographic scope into new regions where our growth strategy can be applied. We intend to pursue opportunities to acquire assets in new regions where we believe growth opportunities are attractive and our business strategies can be successfully applied.

We have set forth in the table below summary information describing the regions in which we have pipeline systems and processing assets.

								Average			Year Ended December 31, 2004
Asset	Pipeline Type	Initial Acquisition Date(1)		Length (miles)		Existing Throughput Capacity (Mcf/d)(2)		Throughput at Time of Acquisition (Mcf/d)(3)			Net Average Throughput Volumes (Mcf/d)		Utilization of Capacity
Copano Pipelines
South Texas Region
Live Oak Area	Gathering		May 2002		112		102,000		9,179			23,280		23	%
Agua Dulce Area(4)	Gathering and Transmission		June 1996		381		78,000		7,850			32,399		42	%
Hebbronville Area	Gathering		September 1994		79		90,000		15,337			29,423		33	%
Karnes Area	Gathering		August 2004		68		17,500		2,000	(5)		9,771		56	%
Webb/Duval Area(6)(7)	Gathering		February 2002		144		219,000		43,046			104,437		48	%
Coastal Waters Region	Gathering		June 1992		142		37,000		1,208			11,403		31	%
Central Gulf Coast Region	Gathering		August 2001		210		155,000		118,804			74,475		48	%
Upper Gulf Coast Region	Gathering and Transmission		April 1997		230		139,000		33,748			40,219		29	%
Total					1,366							325,407
Copano Processing
Houston Central Processing Plant	Processing		August 2001
Inlet volumes									626,764	(8)		529,040
NGLs produced									10,406 Bbls/d	(8)		15,373
Sheridan NGL Pipeline	NGL Transportation		August 2001		104				2,648 Bbls/d	(8)		4,322

(1) The initial acquisition date is the date that we first commenced operations with respect to any area, region and facility.

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

(3) Reflects average throughput for the first month in which we operated the assets.

(4) Throughput volumes presented in the table are net of intercompany transactions. Gross volumes and utilization of capacity in this area totaled 32,816 Mcf/d and 42%, respectively, for the year ended December 31, 2004.

(5) Only reflects throughput volumes on our Runge Gathering System that we acquired and integrated in December 2004. No historical throughput information is available for the Karnes County Gathering System (acquired in August 2004) as no throughput existed in the month prior to acquisition.

(6) Our Webb/Duval Area consists of the Webb/Duval Gathering System and two smaller gathering systems, which are owned by Webb/Duval Gatherers, an unconsolidated partnership in which we hold a 62.5% interest. Throughput volumes for Webb/Duval are presented on a gross basis, without netting volumes attributable to each of the partners.

(7) Throughput volumes presented in the table are net of affiliate transactions. Gross volumes and utilization of capacity in this area totaled 126,305 Mcf/d and 58%, respectively, for the year ended December 31, 2004.

(8) Represents volumes for the month of June 2001. In July 2001, volumes began to be transported from our South Texas Region to the KMTP Laredo-to-Katy pipeline thereby increasing the volume of NGLs produced by our Houston Central Processing Plant and transported on our Sheridan NGL line.

Copano Pipelines

We own approximately 1,366 miles of pipelines used for natural gas gathering and transmission, including approximately 144 miles of pipeline owned by a partnership in which we own a 62.5% interest. For the years ended December 31, 2004 and 2003, we averaged net throughput volumes of 325,407 Mcf/d and 334,142 Mcf/d, respectively, of natural gas. Our facilities are operated in four separate operating regions as described below.

South Texas Region

The South Texas Region consists of eight wholly owned gathering and intrastate transmission systems totaling approximately 640 miles of pipelines operating in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces and San Patricio Counties, Texas. This region is composed of several operating pipeline systems including the Live Oak System, the Clayton Pipeline, the Agua Dulce System, the Nueces County System, the Mesteña Grande System, the Hebbronville Pipeline, the Karnes County Gathering System and the Runge Gathering System. This region is managed from our field office in Alice, Texas. In addition, our employees in this region are responsible for the operations of Webb/Duval Gatherers, as more fully described below.

Live Oak Area

Our Live Oak Area is comprised of two gathering systems, the Live Oak System and the Clayton Pipeline.

Live Oak System. The Live Oak System is an approximately 54-mile pipeline system that gathers natural gas from fields located in Live Oak County, Texas. The Live Oak System is composed of a 12-inch diameter mainline and two 8-inch diameter main gathering lateral lines, the Bennett lateral and the Patteson lateral, which extend into southern and eastern Live Oak County. The system also includes several smaller lines that range in size from two inches to eight inches in diameter. We currently gather natural gas from approximately 29 active receipt points representing 12 producers and three shippers connected to our Live Oak System. All of the natural gas from the Live Oak System is compressed, dehydrated and delivered to the KMTP Laredo-to-Katy pipeline for treating, conditioning and/or processing at our Houston Central Processing Plant.

In February 2002, we expanded our compression and dehydration facilities providing a throughput capacity of 50,000 Mcf/d. We currently operate 2,060 horsepower of compression and 40,000 Mcf/d of dehydration capacity. Average throughput volume on this system was 21,278 Mcf/d for the year ended December 31, 2004, up from 18,917 Mcf/d for the year ended December 31, 2003.

Clayton Pipeline. The Clayton Pipeline is an approximately 58-mile pipeline extending through Atascosa, Live Oak and Duval Counties, Texas. The northern 34 miles consists of 10-inch diameter pipeline and the southern 22 miles consists of 16-inch diameter pipeline. There are approximately two miles of 3-inch to 6-inch diameter feeder pipelines. We currently transport natural gas on the Clayton Pipeline from seven active receipt points including the Pueblo Midstream Fashing plant in Atascosa County, representing four producers as well as the Fashing plant tailgate interconnect. All natural gas is delivered to Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.). We have recently completed a pipeline interconnect that will be used to transport natural gas for a third party, which we anticipate to begin flowing during the second quarter of 2005. There is an existing inactive interconnect with Natural Gas Pipeline Company of America, or NGPL, on the southern end of the Clayton Pipeline. The Clayton Pipeline has no compression or dehydration facilities.

Average throughput volume on the Clayton Pipeline was 2,002 Mcf/d for the year ended December 31, 2004 and 4,736 Mcf/d for the year ended December 31, 2003. The Clayton Pipeline has a capacity of 52,000 Mcf/d.

Agua Dulce Area

Our Agua Dulce Area consists of two primary pipeline assets, the Agua Dulce System and the Nueces County System.

Agua Dulce System. The Agua Dulce System is an approximately 240-mile gathering system located in Duval, Jim Wells and Nueces Counties, Texas. The Agua Dulce System is composed of (i) the East Duval lateral, a 17-mile, 10-inch diameter mainline that originates near Agua Dulce, Texas in Jim Wells County, and terminates at an interconnect with the Webb/Duval Gathering System and (ii) several distinct gathering systems that deliver natural gas to the East Duval lateral. There are approximately 240 miles of 2-inch to 12-inch diameter gathering pipelines that supply the East Duval lateral. We currently gather natural gas from 41 active receipt points, representing 25 producers and one shipper. Since purchasing the system, we have added approximately 9 miles of pipeline, including the 6-mile, 12-inch diameter line that connected the system to the Webb/Duval Gathering System in 2002. We currently have 5,525 horsepower of compression and 44,000 Mcf/d of dehydration capacity installed on this system. Natural gas is gathered and transported through the Agua Dulce System into the Webb/Duval Gathering System, which can deliver this natural gas into the KMTP Laredo-to-Katy pipeline. The Agua Dulce System has inactive interconnects with GulfTerra Energy Partners (a subsidiary of Enterprise Products Partners, L.P.), Humble Gas Pipeline Company (an affiliate of ExxonMobil), and Duke Energy Field Services.

Average net throughput volume on this system was 22,196 Mcf/d for the year ended December 31, 2004, up from 7,429 Mcf/d for the year ended December 31, 2003. The Agua Dulce System has an estimated capacity of 37,000 Mcf/d.

Nueces County System. The Nueces County System is an approximately 141-mile pipeline system that gathers natural gas in Nueces and San Patricio Counties, Texas. The Nueces County System is composed of gathering and transmission lines ranging in size from two inches to 12 inches in diameter. The Nueces County System currently gathers natural gas from 17 active receipt points representing nine producers. Natural gas from this system is gathered and delivered to Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.) and to our Agua Dulce System. We currently have 85 horsepower of compression and 33,000 Mcf/d of dehydration capacity installed on this system.

Average throughput volume on this system was 10,203 Mcf/d for the year ended December 31, 2004 and 15,468 Mcf/d for the year ended December 31, 2003. The Nueces County System has an estimated capacity of 41,000 Mcf/d under current operating pressures.

Hebbronville Area

There are two major pipelines that encompass the Hebbronville area, the Mesteña Grande System and the Hebbronville Pipeline.

Mesteña Grande System. The Mesteña Grande System is an approximately 56-mile pipeline system located in the southern portion of Jim Hogg County and the northern half of Duval County, Texas. The Mesteña Grande System currently gathers natural gas from 18 active receipt points, representing five producers and one shipper. This system consists of pipelines ranging in size from 4 inches to 8 inches in diameter. All natural gas gathered from the Mesteña Grande System is transported for delivery to KMTP via our Hebbronville Pipeline. We have 4,020 horsepower of compression installed on this system and 80,000 Mcf/d of dehydration capacity.

Hebbronville Pipeline. The Hebbronville Pipeline was constructed by us in 2001 and is an approximately 23-mile pipeline comprised of 12-inch diameter pipeline and 16-inch diameter pipeline, which transports all of the natural gas from the Mesteña Grande System for delivery to the KMTP Laredo-to-Katy pipeline. The Hebbronville Pipeline has two active receipt points representing one shipper. There is no installed compression or dehydration on this pipeline.

Average throughput volume on these pipelines was 29,423 Mcf/d on a combined basis for the year ended December 31, 2004, down from 40,345 Mcf/d for the year ended December 31, 2003. The Mesteña Grande System currently has an estimated capacity of 90,000 Mcf/d and the Hebbronville Pipeline has an estimated capacity of 250,000 Mcf/d. Without additional compression, however, the combined capacity of these pipelines is limited to 90,000 Mcf/d.

Karnes Area

The Karnes Area is comprised of two natural gas gathering systems, the Karnes County Gathering System and the Runge Gathering System.

Karnes County Gathering System. The Karnes County Gathering System is an approximately 15-mile pipeline operating in northern Bee and southern Karnes Counties, Texas. This system is comprised of natural gas pipelines ranging in size from 10 inches to 16 inches in diameter. The Karnes County Gathering System gathers natural gas from one active receipt meter connected to a third party. Natural gas transported on the Karnes County Gathering System is delivered to the KMTP Laredo-to-Katy pipeline and is processed or conditioned at our Houston Central Processing Plant. We have 2,060 horsepower of compression installed on this system. We acquired this system in August 2004 and initial flow of natural gas commenced on September 10, 2004.

Runge Gathering System. The Runge Gathering System is comprised of 53 miles of natural gas pipelines located in Bee, DeWitt, Goliad and Karnes Counties, Texas and was acquired from Kinder Morgan Tejas Pipeline, L.P. effective December 1, 2004 with our operation of the system commencing on that date. The acquisition was accomplished at no cost to us (other than transaction and integration costs) by dedicating the natural gas supplies connected and flowing into the Runge Gathering System prior to October 1, 2004 to KMTP for purchase under a long-term agreement at a purchase price favorable to KMTP. We are free to attach new supplies of natural gas to the system that we can then sell at market prices. This system is comprised of 37 miles of natural gas pipelines ranging in size from 4 inches to 8 inches and a 16-mile 4 inch natural gas liquids pipeline which was converted to natural gas service to provide delivery of natural gas from the Runge Gathering System to our Karnes County Gathering System. When we acquired the Runge Gathering System in December 2004, approximately 2,000 Mcf/d was flowing into the Runge Gathering System. Natural gas from the Runge Gathering System is gathered and redelivered into the Karnes County Gathering System which is then delivered to the KMTP Laredo-to-Katy pipeline and is processed or conditioned at our Houston Central Processing Plant. This system has seven active receipt meters.

Average throughput volume on these pipelines was 9,771Mcf/d on a combined basis for the period from acquisition through December 31, 2004.

Webb/Duval Area

Our Webb/Duval Area is comprised of the Webb/Duval Gathering System, the Olmitos Gathering System and the Cinco Compadres Gathering System, each of which is owned by Webb/Duval Gatherers, a general partnership that we operate and in which we hold a 62.5% interest. Our original investment in the Webb/Duval Area was made in November 2001 when we acquired our initial 15% partnership interest in Webb/Duval Gatherers, which, at the time, only owned the Webb/Duval Gathering System. In February 2002, we acquired an additional 47.5% partnership interest in Webb/Duval Gatherers, and

Webb/Duval Gatherers purchased the Olmitos and Cinco Compadres Gathering Systems. As the holder of a 62.5% interest in the partnership that owns these pipeline systems, we operate these systems subject to certain rights of the other partners, including the right to approve capital expenditures in excess of $0.1 million, financing arrangements by the partnership or any expansion projects associated with these systems. In addition, each partner has the right to use its pro rata share of pipeline capacity on these systems subject to applicable ratable take and common purchaser statutes.

Webb/Duval Systems. The Webb/Duval Gathering System is a 121-mile pipeline located in Webb and Duval Counties, Texas, and is comprised of 3-inch and 16-inch diameter pipelines. Following our construction of a 6-mile, 12-inch diameter pipeline in 2002, the Webb/Duval Gathering System connects our Agua Dulce System to the KMTP Laredo-to-Katy pipeline. We currently have 29 active receipt points connected to the Webb/Duval Gathering System, representing 13 shippers. We currently have 7,468 horsepower of installed compression and no dehydration on this system. The Olmitos Gathering System and the Cinco Compadres Gathering System are smaller non-contiguous gathering systems that are part of Webb/Duval Gatherers’ assets. The Olmitos Gathering System is a 14-mile pipeline located in Webb County, Texas, and is comprised of 4-inch to 8-inch diameter pipelines. The Cinco Compadres Gathering System is a 9-mile pipeline located in Webb County, Texas, and is comprised of 3-inch to 6-inch diameter pipelines.

Average total throughput volume on these combined systems including volumes delivered by our Agua Dulce System was 126,305 Mcf/d for the year ended December 31, 2004, up from 102,726 Mcf/d for the year ended December 31, 2003. Excluding the volume received from our Agua Dulce System described previously, the average throughput volume on these systems was 104,437 Mcf/d for the year ended December 31, 2004, up from 95,341 Mcf/d. Differences in volumes between the Webb/Duval Gathering Area and the Agua Dulce systems are attributable to gas consumed as fuel during dehydration and compression, ordinary pipeline system gains and losses and the fact that the Agua Dulce System used alternate interconnects before its connection during 2002 to the Webb/Duval Gathering System. The Webb/Duval Gathering System has an estimated current capacity of 219,000 Mcf/d. We generate gross margins from transportation of natural gas across these majority-owned pipelines.

Coastal Waters Region

The Coastal Waters Region is comprised of two pipeline systems, the Copano Bay System and the Encinal Channel Pipeline, consisting of approximately 142 miles of pipelines operating both onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. This region is managed from our field office in Lamar, Texas.

Copano Bay System. The Copano Bay System currently comprises approximately 119 miles of natural gas pipelines, which range in size from three inches to 12 inches in diameter. Currently, the Copano Bay System gathers natural gas from the offshore Matagorda Island Block 721 area, Aransas and Copano Bays, and adjacent onshore lands through Aransas Bay and onshore at Rockport, Texas. Natural gas and condensate are separated at our Lamar separation and dehydration facility, and the natural gas is delivered to GulfTerra Energy Partners (a subsidiary of Enterprise Products Partners, L.P.)/Channel at Lamar, Texas. The condensate is stored and redelivered to producers and shippers who then truck the product to market. The Copano Bay System gathers or transports substantially all of the natural gas in the Copano Bay and Aransas Bay area. In 2003, we installed 15,000 Mcf/d of additional dehydration capacity (for a total of approximately 25,000 Mcf/d of dehydration capacity) on the northern end of the Copano Bay System. The throughput capacity of this system is 37,000 Mcf/d. The Copano Bay System has nine active receipt points, representing nine producers and one shipper.

Average throughput volume on this system was 11,403 Mcf/d for the year ended December 31, 2004, down from 20,541 Mcf/d for the year ended December 31, 2003.

Encinal Channel Pipeline. The Encinal Channel Pipeline is an approximately 23-mile pipeline that is currently inactive. The Encinal Channel Pipeline measures three inches to 12 inches in diameter and is located in Nueces and San Patricio Counties, Texas. The Encinal Channel Pipeline currently has an estimated throughput capacity of 145,000 Mcf/d. There is no installed compression or dehydration on this pipeline. We believe inland bay lease sales will ultimately provide natural gas purchase and transportation opportunities for this pipeline.

Central Gulf Coast Region

The Central Gulf Coast Region is composed of two intrastate natural gas gathering systems totaling approximately 210 miles and operating in Colorado, Dewitt, Lavaca and Wharton Counties, Texas. This region is operated from our Houston Central Processing Plant located approximately 100 miles southwest of Houston. Interconnects at the tailgate of the our Houston Central Processing Plant include KMTP, Tennessee Gas Pipeline, Texas Eastern Transmission and Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.).

Sheridan System. The Sheridan System consists of approximately 60 miles of natural gas gathering lines ranging in size from four inches to 10 inches in diameter, and gathers natural gas from 17 active receipt points and one third-party pipeline interconnect located in Colorado and Lavaca Counties, Texas, representing 14 producers and four shippers. There is no installed compression or dehydration on this system. Natural gas from the Sheridan System is gathered and transported to our Houston Central Processing Plant for treatment of carbon dioxide, processing and ultimate delivery into the interconnects at the tailgate of our processing plant. The Sheridan System also has a pipeline interconnect with the Enterprise Products Chesterville System. Average throughput volume on this system was 18,338 Mcf/d for the year ended December 31, 2004, up from 15,284 Mcf/d for the year ended December 31, 2003. The Sheridan System has an estimated capacity of 45,000 Mcf/d.

Provident City System. This system consists of approximately 150 miles of natural gas gathering lines ranging in size from three inches to 14 inches in diameter, and gathers natural gas from 65 receipt points and one third-party pipeline interconnect located in Colorado, DeWitt, Lavaca and Wharton Counties, Texas, representing 40 producers and two shippers. There is no compression or dehydration installed on this system. The Provident City System has a pipeline interconnect with Duke Energy Field Services’ San Jacinto Pipeline System. Average throughput volume on this system was 56,137 Mcf/d for the year ended December 31, 2004 down from 65,068 Mcf/d for the year ended December 31, 2003. The Provident City System has an estimated capacity of 110,000 Mcf/d.

Upper Gulf Coast Region

Our Upper Gulf Coast Region is composed of three pipeline systems consisting of approximately 230 miles of pipeline used for gathering, transportation and sales of natural gas in Houston, Walker, Grimes, Montgomery and Harris Counties, Texas. This region is managed from our field office in Conroe, Texas.

Sam Houston System. The Sam Houston System includes approximately 125 miles of natural gas pipeline that gathers natural gas and receives natural gas from other pipelines for ultimate delivery to markets on the system. This gathering and transportation pipeline ranges in size from four inches to 12 inches in diameter. We currently gather natural gas from 22 active receipt points and five third-party pipeline interconnects, representing eight producers and five shippers.

The Sam Houston System has interconnects with Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.), Lone Star Pipeline Company, KMTP, Vantex Gas Pipeline Company and Texas Eastern Transmission. The Sam Houston System delivers natural gas to multiple CenterPoint Energy city gates in The Woodlands, Conroe and Huntsville, Texas, to Universal Natural Gas, a gas company providing services to residential markets in southern Montgomery County, Texas and to Entergy’s Lewis

Creek Generating Plant and several industrial consumers. There is no compression or dehydration installed on this pipeline system. Average net throughput volume on this system was 33,489 Mcf/d for the year ended December 31, 2004, down from 38,449 Mcf/d for the year ended December 31, 2003. The Sam Houston System has an estimated capacity of approximately 119,000 Mcf/d.

Grimes County System. The Grimes County System is an approximately 77-mile natural gas gathering system located in Grimes County, Texas, which consists of natural gas pipelines ranging in size from two inches to 12 inches in diameter. We currently gather natural gas from eight active receipt points representing five producers, and deliver all of the natural gas to our Sam Houston System. There is 311 horsepower of compression and no active dehydration on this pipeline system.

Average throughput volume on this system was 2,514 Mcf/d for the year ended December 31, 2004, up from 1,155 Mcf/d for the year ended December 31, 2003. The Grimes County System has an estimated capacity of 23,000 Mcf/d.

Lake Creek Pipeline. The Lake Creek Pipeline is an approximately 28-mile natural gas pipeline system located in Harris and Montgomery Counties, Texas. The Lake Creek Pipeline is comprised of 6-inch and 8-inch diameter natural gas pipelines. This pipeline has three receipt points and a bi-directional receipt and delivery point with Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.) near the Bammel Storage field in Harris County.

The majority of the natural gas transported on this pipeline is delivered to CenterPoint Energy at delivery points serving the western portion of The Woodlands, Texas and the surrounding area. Natural gas is also delivered to Universal Natural Gas. Average throughput volume on this system was 4,216 Mcf/d for the year ended December 31, 2004, down from 11,409 Mcf/d for the year ended December 31, 2003. The Lake Creek Pipeline has an estimated capacity of 20,000 Mcf/d.

Copano Processing

The Copano Processing segment includes our Houston Central Processing Plant located near Sheridan, Texas in Colorado County and our Sheridan NGL Pipeline that runs from the tailgate of the processing plant to the Houston area.

Houston Central Processing Plant. Our Houston Central Processing Plant is the third largest in the state of Texas in terms of throughput capacity and the second largest and the most fuel efficient processing plant in the areas in which we operate. Our Houston Central Processing Plant removes NGLs from the natural gas supplied by the KMTP Laredo-to-Katy pipeline, which it straddles, and the pipelines in our Central Gulf Coast Region gathering systems and fractionates the NGLs into separate marketable products for sale to third parties. The Houston Central Processing Plant was originally constructed in 1965 by Shell and was comprised of a single refrigerated lean oil train and a fractionation facility. The plant was modified by Shell in 1985 with the addition of a second refrigerated lean oil train and in 1986 with the addition of a cryogenic turbo-expander train. This 700 MMcf/d gas processing plant includes 6,689 horsepower of inlet compression, 8,400 horsepower of tailgate compression, a 700 gallon per minute amine treating system for removal of carbon dioxide and low-level hydrogen sulfide, two 250 MMcf/d refrigerated lean oil trains, one 200 MMcf/d cryogenic turbo-expander train, a 25,000 Bbl/d NGL fractionation facility, and 882,000 gallons of storage capacity for propane, butane and natural gasoline mix and stabilized condensate. The plant also has multiple tailgate interconnects for redelivery of natural gas with KMTP, Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.), Tennessee Gas Pipeline Company and Texas Eastern Transmission. In addition, at the tailgate of the plant, we operate our Sheridan NGL Pipeline for transporting butane and natural gasoline mix, Dow Chemical operates a 6-inch diameter pipeline for transportation of ethane and propane to Dow’s Freeport facility and TEPPCO operates an 8-inch diameter crude oil and stabilized condensate pipeline that runs to refineries in the

greater Houston area. Our Houston Central Processing Plant and related facilities are located on a 163-acre tract of land, which we lease under three long-term lease agreements.

In 2003, we modified the processing plant to provide natural gas conditioning capability by installing two new 700 horsepower, electric-driven compressors to provide propane refrigeration through the lean oil portion of the plant, which enables us to shut down one of our steam-driven turbines when we are conditioning natural gas. These modifications provide us with the capability to process gas only to the extent required to meet pipeline hydrocarbon dew point specifications. Our ability to condition gas, rather than fully process it, provides us with significant benefits during periods when processing is not economic (when the price of natural gas is high compared to the price of NGLs), including:

· providing us with the ability to minimize the level of NGLs removed from the natural gas stream during periods when the price of natural gas is higher than NGLs; and

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

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

Our Houston Central Processing Plant has an inlet capacity of approximately 700,000 Mcf/d and had an average throughput of 529,040 Mcf/d for the year ended December 31, 2004. This compares with an average daily throughput of 479,127 Mcf/d for the year ended December 31, 2003. The average daily volume of ethane and propane delivered from the plant to the Dow NGL pipeline was 10,667 Bbls/d and 4,981 Bbls/d for 2004 and 2003, respectively. The average daily volume of butane and natural gasoline mix delivered to the Sheridan NGL pipeline was 4,322 Bbls/d and 2,758 Bbls/d for 2004 and 2003, respectively. The average daily volume of stabilized condensate delivered from the plant to the TEPPCO crude oil pipeline was 379 Bbls/d and 241 Bbls/d for 2004 and 2003, respectively.

Sheridan NGL Pipeline. Our 104-mile, 6-inch diameter Sheridan NGL pipeline originates at the tailgate of our Houston Central Processing Plant and currently delivers butane and natural gasoline mix into the Enterprise Products Partners’ Seminole Pipeline for ultimate redelivery for further transportation and fractionation. We also have the ability to deliver the ethane and propane through the Sheridan NGL line for redelivery to Enterprise’s Seminole Pipeline if the Dow pipeline were unavailable. The line has a current capacity of 20,840 Bbls/d of NGLs, which we believe could be increased with the installation of additional pump facilities. Average throughput volume on this system was 4,322 Bbls/d for the year ended December 31, 2004 as compared with 2,758 Bbls/d for the year ended December 31, 2003.

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, fractionation and transportation. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

We provide natural gas gathering, treating, conditioning, processing, fractionation, transportation, dehydration and compression services to our customers. These processes are illustrated in the following diagram.

· Natural gas gathering and compression. The natural gas gathering process begins with the drilling of wells into gas 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 transport it to larger pipelines for further transmission. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells.

· Lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to the gathering system and continue to produce for longer periods of time. As the well pressure declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting 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. Compression allows 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 cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering natural gas that otherwise would not be produced.

· Natural gas dehydration. Produced natural gas is saturated with water, which must be removed because the combination of natural gas and water can form ice that can plug many different parts of the pipeline gathering and transportation system. 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 and cause a greater pressure drop downstream. To avoid these potential issues and to meet downstream pipeline and end-user gas quality standards, natural gas is dehydrated to remove the saturated water.

· Natural gas treating and blending. Natural gas has a varied composition 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. Natural gas with high carbon dioxide or hydrogen sulfide levels 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 marketable, 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.

· 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 the 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. Our facility has a circulation capacity of 700 gallons per minute.

· Natural gas processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components. Natural gas is processed not only to remove unwanted NGLs that would interfere with pipeline transportation or use of the natural gas, but also to separate from the gas those hydrocarbon liquids that have higher value as NGLs. The 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 processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream.

· 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 of natural gas removes only an absolute minimum amount of NGLs (typically the components of pentane and heavier products) from the gas stream. To lower the hydrocarbon dew point of a natural gas stream, the temperature of the gas is reduced. Cryogenic processing consumes more fuel because it involves significantly lower temperatures than are required for conditioning of natural gas. We utilize propane refrigeration to more accurately and efficiently control the temperature used to condition the natural gas stream. Conditioning of natural gas, rather than processing, is preferred during periods of unfavorable processing margins.

· NGL fractionation. Fractionation is the process by which NGLs are further 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 butadiene (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 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 utilized 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

As we purchase natural gas, we establish a margin by selling natural gas for physical delivery to third party users. Through these transactions, we seek to maintain a balance between our purchases and our sales or future delivery obligations. To mitigate price basis risk, we also attempt to utilize the same reference index for the establishment of price with respect to a sale transaction as utilized in the related purchase transaction. Our practice is not to acquire and hold natural gas future contracts or derivative products for the purpose of speculating on price changes.

Competition

The natural gas gathering, transmission, treating, processing and marketing industries are highly competitive. We face strong competition in acquiring new natural gas supplies. Our competitors include major interstate and intrastate pipelines, and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency, flexibility and reliability of the gatherer, the pricing arrangements offered by the gatherer, the location of the gatherer’s pipeline facilities and the ability of the gatherer to offer a full range of services, including processing, conditioning and treating services. We provide comprehensive services to natural gas producers, including natural gas gathering, transportation, compression, dehydration, treating, conditioning and processing. We believe our ability to furnish these services gives us an advantage in competing 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 due in part to the elimination of some field equipment and greater economies of scale at our Houston Central Processing Plant. 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 services on competitive terms. In addition, with respect to natural gas customers attached to our pipeline systems, we are able to vary quantities of natural gas delivered to customers in response to market demands.

The primary difference between us and many of our competitors is that we provide an integrated and responsive package of midstream services, while many of our competitors typically offer only a few select services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies.

Many of our competitors have capital resources and control supplies of natural gas greater than ours. Our major competitors for natural gas supplies and markets in our four operating regions include GulfTerra Energy Partners (a subsidiary of Enterprise Products Partners, L.P.), Lobo Pipeline Company (an affiliate of ConocoPhillips), KMTP, Duke Energy Field Services, Crosstex Energy, and Houston Pipe Line Company (an affiliate of Energy Transfer Partners, L.P.). Our primary competitors for our processing business are GulfTerra Energy Partners (a subsidiary of Enterprise Products Partners, L.P.), ExxonMobil and Duke Energy Field Services.

Natural Gas Supply

Our assets are located in four pipeline operating regions in Texas that have experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies. We generally do not obtain independent evaluations of 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 systems or the anticipated life of such producing reserves.

During the year ended December 31, 2004, our top producers by volume of natural gas were Noble Energy, Mesteña Operating, Westport Oil and Gas Company (a subsidiary of Kerr-McGee), Dominion OK TX Exploration and Production and Gryphon Exploration, which collectively accounted for approximately 37% of the natural gas delivered to our natural gas gathering and intrastate pipeline systems during that period.

We contract for supplies of natural gas from producers primarily under two types of arrangements, natural gas purchase contracts and fee-for-service contracts. The primary term of each contract varies significantly, ranging from one month to the life of the dedicated production. The specific terms of each natural gas supply contract are based upon a variety of factors including gas quality, pressure of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. For a detailed discussion of our contracts, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Our Contracts—Our Natural Gas Supply and Transportation Contracts.”

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 that was previously transported on other gathering systems.

Credit Risk and Significant Customers

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

During the year ended December 31, 2004, we had three customers that collectively accounted for slightly more than 60% of our consolidated revenue. During the year ended December 31, 2003, we had four customers that collectively accounted for almost 65% of our consolidated revenue. During the year ended December 31, 2002, we had three customers that collectively accounted for almost 63% of our consolidated revenue. Please read Note 12 to the Consolidated Financial Statements, “Customer Information” for additional information about our significant customers.

Kinder Morgan Texas Pipeline

KMTP is an intrastate natural gas pipeline system that is principally located in the Texas Gulf Coast area. KMTP transports natural gas from producing fields in South Texas, the Texas Gulf Coast and the Gulf of Mexico to markets in southeastern Texas. KMTP acts as a seller of natural gas as well as a transporter. We utilize KMTP as a transporter because our Houston Central Processing Plant straddles its 30-inch diameter Laredo-to-Katy pipeline. By using KMTP as a transporter, we can transport natural gas from many of our pipeline systems to our processing plant and downstream markets. Under our contractual arrangement related to KMTP Gas, we receive natural gas at our plant, process or condition the natural gas and sell the NGLs to third parties at market prices. We refer to the natural gas delivered into KMTP’s pipeline from sources other than our gathering systems as “KMTP Gas.” Because the extraction of NGLs from the natural gas stream during processing or conditioning reduces the Btus of the natural gas, our arrangement with KMTP requires us to purchase natural gas at market prices to replace the loss in Btus. Pursuant to an amendment to this contract with KMTP, effective January 1, 2004, we pay a fee to KMTP based on the NGL content of the KMTP Gas only during periods of favorable processing margins. In addition, the amendment provides that during periods of unfavorable processing margins, KMTP pays us a fixed fee plus an additional payment based on the index price of natural gas. Our contract arrangement relating to KMTP Gas expires on August 31, 2006, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior notice.

For the year ended December 31, 2004, approximately 86% of the natural gas volumes processed or conditioned at our Houston Central Processing Plant were delivered to the plant through the KMTP Laredo-to-Katy pipeline while the remaining 14% were delivered directly into the plant from our gathering systems. Of the natural gas delivered into the plant from the KMTP Laredo-to-Katy pipeline, approximately 23% was delivered from gathering systems controlled by us and 77% was delivered into KMTP’s pipeline from other sources. Of the total volume of NGLs extracted at the plant during this period, 45% was attributable to KMTP Gas, while 55% was attributable to gas from gathering systems controlled by us, including our gathering systems connected directly to the plant.

Regulation

Regulation by the FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or the FERC, does not directly regulate any of our operations. However, the FERC’s regulation influences certain aspects of our business and the market for our products. In general, the FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

· the certification and construction of new facilities;

· the extension or abandonment of services and facilities;

· the maintenance of accounts and records;

· the acquisition and disposition of facilities;

· the initiation and discontinuation of services; and

· various other matters.

In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Intrastate Pipeline Regulation. Our intrastate natural gas pipeline operations generally are not subject to rate regulation by the FERC, but they are subject to regulation by the State of Texas. However, to the extent that our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to the FERC jurisdiction under Section 311 of the Natural Gas Policy Act, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline.

Some of our operations are subject to the Texas Gas Utility Regulatory Act, as implemented by the Railroad Commission of Texas, or the TRRC. Generally the TRRC is vested with authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. We own a number of intrastate natural gas pipelines that we believe would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

We are subject to state ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. 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.

Sales of Natural Gas. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas

industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.

Environmental Matters

The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids 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 our wastes;

· limiting or prohibiting construction activities in 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 limiting or prohibiting future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances 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 other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus 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. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat, process and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of certain environmental and safety concerns that relate to the midstream natural gas industry.

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 plant 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 strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We likely will 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 believe, however, that our operations will not 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.

Hazardous Waste. Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or 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 as well as natural gas is 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 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 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, gathering, field compression and processing of natural gas. Although we used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of 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, whether

from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, 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 waters of the United States. The discharge of pollutants, including 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 an appropriately issued permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations.

Pipeline Safety. Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases, and the transportation and storage of liquefied natural gas (LNG) and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs that, at this time, cannot reasonably be quantified.

The DOT, through the Office of Pipeline Safety, recently finalized a series of rules intended to require pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. Similar rules are already in place for operators of hazardous liquid pipelines. The Texas Railroad Commission, or TRRC, has adopted similar regulations applicable to intrastate gathering and transmission lines. Compliance with these rules has not had a material adverse effect on our operations but there is no assurance that this trend will continue in the future.

Employee Health and Safety. We are subject to the requirements of the Occupational Safety and Health Act, referred to as 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 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 occupy approximately 15,500 square feet of space at our executive offices in Houston, Texas under a lease expiring on March 31, 2010. At the expiration of the primary term, we have an option to renew this lease for an additional five years at the then prevailing market rates. We also lease office facilities in Alice and Hebbronville, Texas, which consist of approximately 1,863 square feet and 500 square feet of office space, respectively. We own office facilities in Conroe, Sheridan and Lamar, Texas, which consist of approximately 3,000 square feet, 10,000 square feet and 1,200 square feet, respectively. Certain of our owned office facilities are located on land leased by us or on land subject to a permanent easement. 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, 2004, we had no direct employees other than certain Delaware-based officers. To carry out our operations, one of our affiliates, Copano Operations, employed 85 full-time employees on our behalf as of December 31, 2004. Effective January 1, 2005 and pursuant to our general and administrative services agreement with Copano Operations, Copano Operations transferred responsibility to us for a significant portion of the services that it had previously provided to us. As a result, as of March 15, 2005, we had 74 full time employees and Copano Operations continued to employ 12 full-time employees on our behalf. None of our employees are covered by collective bargaining agreements. We consider our relations with these employees, with Copano Operations and with those Copano Operations’ employees providing services to us to be good. In exchange for providing general and administrative services to us, including employing certain personnel on our behalf, we are required to reimburse Copano Operations for its costs and expenses. To the extent these employees will be dedicated to provide services on our behalf, we refer to them as our employees. A brief description of our general and administrative services agreement will be contained in our proxy statement, certain parts of which are incorporated by reference into Part III of this Annual Report.

Item 2. Properties

A description of our properties is contained in Item 1, “Business” of this Annual Report. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. 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 pipeline was 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 all of 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. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the fourth quarter of 2004.

PART II

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

Our common units representing limited liability company interests in us are listed on The NASDAQ National Market, or NASDAQ, under the symbol “CPNO.” Our common units began trading on November 9, 2004, following our initial public offering. Our initial public offering price was $20.00 per common unit. On March 28, 2005, the market price for our common units was $29.50 per unit. There were approximately 3,100 common unitholders, of which there were approximately 20 common unitholders of record. Additionally, there were 12 unitholders of record of our subordinated units. There is no established public trading market for our subordinated units.

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

					Cash
	Common Unit				Distribution
	Price Range				Paid Per
	High		Low		Unit
2004:
Quarter Ended December 31	$	28.50	$	23.25		$	0.20	(1)

(1) The distribution for the quarter ended December 31, 2004 was paid on February 14, 2005 to holders of record as of the close of business on February 1, 2005 and reflected a pro rata portion of our $0.40 per unit minimum quarterly distribution, covering the period from the November 15, 2004 closing of our initial public offering through December 31, 2004.

Within 45 days after the end of each quarter, we intend to pay quarterly in arrears (in February, May, August and November of each year), to the extent we have sufficient available cash from operating surplus as defined in our limited liability company agreement, the minimum quarterly distribution of $0.40 per unit (or $1.60 per year), to our common and subordinated unitholders of record on the applicable record date. During the subordination period (as described below), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.40 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Our available cash consists generally of all cash on hand at the end of the fiscal quarter, less reserves that our board determines are necessary to a) provide for the proper conduct of our business; b) comply with applicable law, any of our debt instruments, or other agreements; or (c) provide funds for distributions to our unitholders for any one or more of the next four quarters; plus all cash on hand for the quarter resulting from eligible working capital borrowings made after the end of the quarter on the date of determination of available cash. Operating surplus generally consists of cash on hand at closing, cash generated from operations after deducting related expenditures and other items, plus eligible working capital borrowings after the end of the quarter, plus $12.0 million, as adjusted for reserves. We have not established a credit facility that provides for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders.

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

The amount of available cash from operating surplus needed to pay the minimum quarterly distribution to our common and subordinated unitholders is as follows (in thousands):

	One Quarter			Four Quarters
Common units(1)		$	2,815		$	11,261
Subordinated		1,408			5,631
Total		$	4,223		$	16,892

(1) Excludes distributions attributable to restricted units as distributions made on restricted units issued to date are subject to the same vesting provisions as the restricted units. On December 13, 2004, we awarded 3,000 restricted common units to each of our six independent directors, for a total of 18,000 units. Each restricted unit granted to our independent board members vests in equal one-third annual installments commencing on the first anniversary of the grant date or upon a change of control, death, disability or, in certain circumstances, retirement. Annual distributions related to these restricted units are less than $30,000.

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.40 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

The subordination period will extend until the first day of any quarter beginning after December 31, 2006 in which each of the following tests are met:

· distributions of available cash from operating surplus on each of the outstanding common units and subordinated units for two consecutive four-quarter periods immediately preceding that date equaled or exceeded the minimum quarterly distribution;

· the “adjusted operating surplus” as defined in our limited liability company agreement generated during the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units; and

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

Upon expiration of the subordination period, all subordinated units will convert into common units on a one-for-one basis and will then participate, pro rata, with the other common units in distributions of available cash, and the common units will no longer be entitled to arrearages.

Please read the information incorporated by reference under Item 12, “Security Ownership of Certain Beneficial Owners and Management” of this Annual Report, regarding securities authorized for issuance under our equity compensation plans which information is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

In connection with our initial public offering in November 2004, we used the net proceeds from the exercise of the underwriters’ over-allotment option to redeem 375,000 common units from affiliates of Credit Suisse First Boston Private Equity (“CSFB”) and 375,000 common units from affiliates of EnCap Investments L.P. (“EnCap”). The redemption price for the common units was $18.60 per common unit, which was the initial public offering price to our public common unitholders less underwriting discounts. There were no other repurchases of our equity securities during the fourth quarter of 2004.

Recent Sales of Unregistered Securities

In connection with our formation and through a series of transactions occurring between August 14, 2001 and November 27, 2001, we issued to Copano Partners, L.P., an affiliate of John R. Eckel, Jr., our Chairman and Chief Executive Officer, 1,030,000 common units (1,299,020 as restated) and 620,000 junior units for assets having a net book value of approximately $4 million. Additionally, through a series of transactions occurring between August 14, 2001 and November 27, 2001, we issued:

· 1,875,000 warrants to purchase common units and 300,000 redeemable preferred units to affiliates of CSFB for $30 million; and

· 1,875,000 warrants to purchase common units and 300,000 redeemable preferred units to affiliates of EnCap for $30 million.

Each of these transactions was exempt from registration under Section 4(2) of the Securities Act as the transaction did not involve a public offering. Between November 1, 2001 and our initial public offering, we issued 88,982 additional redeemable preferred units to CSFB and 88,892 additional redeemable preferred units to affiliates of EnCap in lieu of quarterly cash distributions.

Effective January 2002, we designated 212,000 nonvoting special units of our company, 154,000 of which were designated as common special units and 58,000 of which were designated as junior special units. Of the designated amounts, 54,000 common special units and 18,000 junior special units were sold, effective January 2002, to one of our executive officers and, effective April 2003, an additional 100,000 common special units and 40,000 junior special units were sold to another executive officer of our company. The acquisition price for the common special units and the junior special units was $1.00 per unit and $0.50 per unit, respectively. Each of these transactions was exempt from registration under Section 4(2) of the Securities Act as the transaction did not involve a public offering.

On November 15, 2004, in connection with our initial public offering, all of our equity securities outstanding prior to our initial public offering (including the equity securities referred to above) were converted into our common units and subordinated units, and allocated among our pre-offering unitholders pursuant to a pre-arranged formula.

There have been no other sales of unregistered securities within the past three years.

Item 6. Selected Financial Data

Selected Historical Consolidated Financial and Operating Data

The following table shows selected historical consolidated financial and operating data of Copano Energy, L.L.C. for the periods and as of the dates indicated. The selected historical consolidated financial data for the years ended December 31, 2004, 2003, 2002 and 2001 are derived from the audited consolidated financial statements of Copano Energy, L.L.C. The selected historical consolidated financial data for the year ended December 31, 2000 are derived from the unaudited consolidated financial statements of our predecessor entities.

The following table includes the following non-GAAP financial measures: (1) EBITDA and (2) total gross margin. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. We define segment gross margin as revenue less cost of sales. Cost of sales includes the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs purchased by us from affiliates, costs we pay third parties to transport our volumes and costs we pay our affiliates to transport our volumes. For a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read page 27 of this Annual Report.

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. For example, expansion of compression facilities to increase throughput capacity or the acquisition of additional pipelines, such as our recent acquisition of the Karnes County Gathering System, are considered expansion capital expenditures. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. We treat costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets as operations and maintenance expenses as we incur them.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included in Item 8 of this Annual Report. The selected financial information should be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

	Year Ended December 31,
	2004			2003			2002			2001			2000
	(In thousands, except per unit data)
Summary of Operations Data:
Revenues	$	437,656		$	384,571		$	224,896		$	160,369		$	107,381
Cost of sales	386,155			353,376			199,525			143,381			96,028
Operations and maintenance expenses	12,486			10,854			9,562			4,960			1,780
Depreciation and amortization	7,287			6,091			5,539			3,326			2,191
General and administrative expenses	9,217			5,849			4,177			2,171			1,460
Taxes other than income	770			926			891			435			331
Equity in (earnings) loss from unconsolidated affiliate	(419		)	127			584			—			—
Operating income	22,160			7,348			4,618			6,096			5,591
Interest and other financing costs	(23,160		)	(12,108		)	(6,360		)	(2,227		)	(299		)
Interest income and other	85			43			101			183			150
Net (loss) income	$	(915	)	$	(4,717	)	$	(1,641	)	$	4,052		$	5,442
Basic and diluted net (loss) income per unit:(1)	$	(0.35	)	$	(6.21	)	$	(6.77	)	$	2.25
Cash distributions per common unit(1)	$	1.01		$	—		$	0.22		$	0.31
Balance Sheet Data (at period end):
Total assets	$	178,399		$	161,709		$	159,521		$	152,258		$	71,530
Property, plant and equipment, net	119,683			117,032			116,888			109,158			45,427
Payables to affiliates	127			1,371			932			1,090			623
Long-term debt	57,000			57,898			68,740			65,354			3,350
Redeemable preferred units	—			60,982			53,559			48,327			—
Members’ capital	82,356			(662		)	6,577			16,157			49,131
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	17,697		$	15,296		$	8,865		$	13,107		$	4,788
Investing activities	(8,920		)	(6,192		)	(16,817		)	(93,335		)	(3,318		)
Financing activities	(6,369		)	(9,633		)	(2,591		)	93,938			(430		)
Other Financial Data:
Pipeline segment gross margin(2)	$	30,076		$	27,551		$	18,772		$	11,529		$	11,353
Processing segment gross margin(3)	21,425			3,644			6,599			5,459			—
Total gross margin(2)	$	51,501		$	31,195		$	25,371		$	16,988		$	11,353
EBITDA(2)	$	29,532		$	13,482		$	10,258		$	9,605		$	7,932
Maintenance capital expenditures	$	1,790		$	2,281		$	3,781		$	1,175		$	668
Expansion capital expenditures	7,130			3,911			9,323			56,746			2,863
Total capital expenditures	$	8,920		$	6,192		$	13,104		$	57,921		$	3,531
Operating Data:
Pipeline throughput(4) (Mcf/d)	220,970			238,800			247,613			228,657			87,907
Processing plant(3)
Inlet volumes (Mcf/d)	529,040			479,127			571,217			614,521			—
NGLs produced (Bbls/d)	15,373			7,280			12,656			15,227			—

(1) Net (loss) income per unit and cash distributions per common unit are not provided for the year ended December 31, 2000 as this financial information represents financial results of predecessor entities that have been combined for comparative purposes. Net (loss) income per unit is based on the weighted average equivalent units outstanding during the periods presented. For periods prior to our initial public offering, equivalent units were calculated using the weighted average of pre-initial public offering common units and common special units adjusted by a conversion or exchange factor. The computation of diluted units outstanding for all periods presented excludes incremental units related to warrants previously held by preferred unitholders and employee unit options because these equity securities had an anti-dilutive effect as a result of losses reported by us for these periods. After our initial public offering in November 2004, total units outstanding as of December 31, 2004 were 10,575,378 units, comprised of 7,056,252 common units and 3,519,126 subordinated units. Cash distributions for 2002 and 2001 have been restated to reflect the conversion discussed previously and the cash distributions for 2004 relate to the distributions paid to the pre-offering unitholders prior to our initial public offering and are based on equivalent units.

(2) Under the equity method of accounting, these amounts include our equity in the earnings (loss) of Webb/Duval Gatherers, which we own a 62.5% partnership interest, in the amounts of $419, $(127) and $(584) for the years ended December 31, 2004, 2003 and 2002, respectively.

(3) We initiated processing upon acquisition of our Houston Central Processing Plant in August 2001.

(4) Excludes volumes associated with our interest in Webb/Duval Gatherers, which we acquired in November 2001 and February 2002. With respect to assets acquired mid-year, our operating data represents daily volumes for the portion of the year we owned the asset.

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

	Year Ended December 31,
	2004			2003			2002			2001			2000
Reconciliation of total gross margin to operating income:
Operating income	$	22,160		$	7,348		$	4,618		$	6,096		$	5,591
Add:
Operations and maintenance expenses	12,486			10,854			9,562			4,960			1,780
Depreciation and amortization	7,287			6,091			5,539			3,326			2,191
General and administrative expenses	9,217			5,849			4,177			2,171			1,460
Taxes other than income	770			926			891			435			331
Equity in (earnings) loss of unconsolidated affiliate	(419		)	127			584			—			—
Total gross margin	$	51,501		$	31,195		$	25,371		$	16,988		$	11,353
Reconciliation of EBITDA to net (loss) income:
Net (loss) income	$	(915	)	$	(4,717	)	$	(1,641	)	$	4,052		$	5,442
Add:
Depreciation and amortization	7,287			6,091			5,539			3,326			2,191
Interest expense	23,160			12,108			6,360			2,227			299
EBITDA	$	29,532		$	13,482		$	10,258		$	9,605		$	7,932
Reconciliation of EBITDA to cash flows from operating activities:
Cash flow from operating activities	$	17,697		$	15,296		$	8,865		$	13,107		$	4,788
Add:
Cash paid for interest and other financing costs	4,029			3,033			2,543			946			211
Equity in earnings (loss) of unconsolidated affiliate	419			(127		)	(584		)	—			—
Increase (decrease) in working capital	7,387			(4,720		)	(566		)	(4,448		)	2,933
EBITDA	$	29,532		$	13,482		$	10,258		$	9,605		$	7,932

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

You should read the following discussion of our financial condition and results of operation in conjunction with the historical consolidated financial statements and notes thereto included elsewhere in this Annual 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 Annual Report. In addition, the reader should review “Forward-Looking Statements” and “Risk Factors” contained in this Item 7 of this Annual Report for information regarding forward-looking statements made in this discussion and certain risks inherent in our business. Other risks involved in our business are discussed under Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.” References in this Item 7 to “Copano Energy, L.L.C.,” “we,” “our,” “us,” or like terms refer to Copano Energy, L.L.C. and its consolidated subsidiaries.

Overview

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

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

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

· Copano Pipelines is engaged in the gathering and intrastate transmission of natural gas in areas we refer to as the South Texas, Coastal Waters, Central Gulf Coast and Upper Gulf Coast regions. Within this segment, we also provide certain related services including compression, dehydration and marketing of natural gas. For the years ended December 31, 2004 and 2003, this segment generated approximately 58% and 88%, respectively, of our total gross margin.

· Copano Processing is engaged in natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central Processing Plant and Sheridan NGL Pipeline. For the years ended December 31, 2004 and 2003, this segment generated approximately 42% and 12%, respectively, of our total gross margin.

Our segment gross margins are determined primarily by four interrelated variables: (1) the volume of natural gas gathered or transported through our pipelines, (2) the volume of natural gas processed, conditioned or treated at our Houston Central Processing Plant, (3) the level and relationship of natural gas and NGL prices and (4) our current contract portfolio. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. For a discussion of the types of contracts we utilize and management’s analysis of our recent results of operations, please read “—Our Contracts” and “—Our Results of Operation.” Our profitability is also dependent upon prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

The margins we realize from a significant portion of the natural gas that we gather or transport through our pipeline systems decrease in periods of low natural gas prices because our gross margins on

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

How We Evaluate Our Operations

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

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

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

In order to isolate and consistently track changes in commodity price relationships and their impact on our processing segment’s results, we calculate a hypothetical “standardized” processing margin. This processing margin is based on a fixed set of assumptions, with respect to liquids composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our financial results are not derived from this standardized processing margin and the standardized margin is not derived from our financial results. However, we believe this calculation is representative of our current operating commodity price environment and we use this calculation to track commodity price relationships. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices such as volumes, changes in NGL composition, recovery rates and variable contract terms. Our standardized processing margins averaged $0.193 per gallon during the fourth quarter of 2004 compared to $0.077 per gallon during the fourth quarter of 2003. Our standardized processing margins

averaged $0.105 per gallon during the year ended December 31, 2004 compared to $0.002 per gallon during the year ended December 31, 2003. The average standardized processing margin for the period from 1989 through December 31, 2004 is $0.091 per gallon.

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

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

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

Year	General and Administrative Expense Limitation
1		$	1.50 million per quarter
2		$	1.65 million per quarter
3		$	1.80 million per quarter

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

Immediately prior to completion of the initial public offering, we distributed to our pre-offering investors $4 million. Our pre-offering investors deposited these funds in escrow accounts to be used for the purpose of satisfying their respective general and administrative expense reimbursement obligation. If the escrow accounts are exhausted, any further reimbursement obligation will be limited to the amount of the distributions attributable to our common and subordinated units owned by the pre-offering investors immediately prior to our initial public offering. We believe that the escrowed funds, together with the

anticipated distributions on these common units and subordinated units, will provide us with additional assurance that our pre-offering investors will be able to satisfy their respective reimbursement obligations.

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

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

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

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

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

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

How We Manage Our Operations

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

Our Processing and Conditioning Economic Model. We utilize a processing and conditioning economic model to determine whether we should process or condition natural gas at our Houston Central Processing Plant. This model allows management to analyze whether current natural gas and NGL pricing supports operating our Houston Central Processing Plant at full processing mode or whether it is economically more advantageous to operate the plant in a conditioning mode. For a detailed discussion of our processing and conditioning capabilities, please read Item 1, “Business—Copano Processing.”

Flow and Transaction Monitoring Systems. We utilize proprietary systems that track commercial activity on each of our pipelines and monitor the flow of natural gas on our pipelines. For example, we designed and implemented software that tracks each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our pipeline assets. Additionally, we designed and installed a Supervisory Control and Data Acquisition (SCADA) system, which assists management in monitoring and operating our pipeline systems. The SCADA system allows us to monitor our assets at remote locations and respond to changes in pipeline operating conditions from our corporate office.

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

our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines.

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

Our Contracts

We seek to execute contracts with producers and shippers that provide us with positive gross margin in all natural gas and NGL pricing environments. Actual contract terms, however, are based upon 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, our expansion in regions where some types of contracts are more common and other market factors.

Our Natural Gas Supply and Transportation Contracts

Our pipeline segment purchases natural gas for transportation and resale and also transports and provides other services for natural gas that it does not purchase on a fee-for-service basis. For the year ended December 31, 2004, we purchased 68.2% of the natural gas volumes delivered to our pipelines and transported 31.8% on a fee-for-service basis. These volumes exclude volumes associated with Webb/Duval Gatherers, substantially all of which are transported on a fee-for-service basis.

Natural Gas Purchases. Generally, we purchase natural gas attached to our pipeline systems under discount-to-index arrangements. Under these arrangements, we generally purchase natural gas at either (1) a percentage discount to an index price, (2) an index price less a fixed amount or (3) a percentage discount to an index price less a fixed amount. We then gather, deliver and resell the natural gas under arrangements described below. For the year ended December 31, 2004, volumes related to discount-to-index purchase arrangements accounted for 95.3% of total purchased volumes. The gross margins we realize under the arrangements described in clauses (1) and (3) above decrease in periods of low natural gas prices and increase during months of high natural gas prices because these gross margins are based on a percentage of the index price. In many cases, our contracts for natural gas purchases allow us to charge producers fees for treating, compression, dehydration or services other than processing and conditioning.

We also purchase natural gas under a limited number of intra-month, fixed-price arrangements used for balancing our portfolio for the month. Transactions under these arrangements are executed to support intra-month changes in operating conditions, including customer requirements, and not for purposes of speculation. For the year ended December 31, 2004, volumes related to such fixed-price arrangements accounted for 4.8% of total purchased volumes.

Fee-For-Service. We generally transport natural gas on our pipeline systems under fixed fee arrangements pursuant to which our transportation fee income represents an agreed rate per unit of throughput. The revenue we earn from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues from these

arrangements would be reduced. For the year ended December 31, 2004, volumes related to fixed-fee arrangements accounted for 63.9% of total natural gas volumes that we transport on behalf of third-party shippers.

We also derive some transportation fee income based upon percentage-of-index fee arrangements. Under this type of arrangement, the fee we receive for gathering or transporting the natural gas is based upon a percentage of an index price. The fee we realize under this type of arrangement decreases in periods of low natural gas prices and increases during periods of high natural gas prices. For the year ended December 31, 2004, volumes related to percentage-of-index fee arrangements accounted for 2.8% of total transported volumes. For the year ended December 31, 2004, volumes related to a combination of fixed-fee and percentage-of-index fee arrangements accounted for 33.3% of total transported volumes. In many cases, our contracts for natural gas transportation allow us to charge shippers fees for treating, compression, dehydration or services other than processing and conditioning.

Our Natural Gas Sales Contracts

We sell natural gas to other natural gas pipelines, marketing affiliates of integrated oil companies or other midstream companies, utilities, power producers and end-users. We sell natural gas under index-related pricing terms with the exception of a limited number of intra-month fixed-price sales arrangements used for balancing our portfolio for the month. Transactions under these fixed-price arrangements are executed to support intra-month changes in operating conditions, including customer requirements, and not for purposes of speculation.

Our Natural Gas Processing and Conditioning Contracts

With respect to our natural gas processing and conditioning services, we contract under the following types of arrangements:

· Keep-Whole with Fee Arrangements. Under keep-whole with fee arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under these types of arrangements, we also charge producers and third-party transporters a conditioning fee, at all times or in certain circumstances depending upon the terms of the particular contract. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs from the natural gas during processing or conditioning reduces the Btus of the natural gas. To replace these Btus, we must purchase natural gas at market prices for return to producers and transporters. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and our revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, we are generally able to reduce our commodity price exposure by conditioning rather than processing the natural gas, as described below. For the year ended December 31, 2004, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 82.5% of total volumes.

· Keep-Whole Without Fee Arrangements. Under keep-whole without fee arrangements, we receive natural gas from the producer or third-party transporter, process the natural gas and sell the resulting NGLs to third parties at market prices. Like the arrangement described above, under these contracts we are required to replace the Btus reduced during processing or conditioning. These contracts are subject to all of the considerations described in “Keep-whole with fee arrangements” above, except that we do not charge the producer or transporter a conditioning fee. It is generally not our policy to enter into new keep-whole contracts without fee arrangements. For

the year ended December 31, 2004, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 13.8% of total volumes.

· Percentage-of-Proceeds Arrangements. Under percentage-of-proceeds arrangements, we generally receive and process natural gas on behalf of producers, sell or redeliver the resulting residue gas and sell the NGL volumes at index-related prices. We remit to producers an agreed upon index-related price for the natural gas, if not redelivered, and an agreed upon percentage of the NGL proceeds. Under these types of arrangements, our revenues and gross margins increase as NGL prices increase, and our revenues and gross margins decrease as NGL prices decrease. For the year ended December 31, 2004, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for 3.3% of total volumes.

· Fixed Fee, or Tolling, Arrangements. Under fixed fee arrangements, producers pay us a fixed fee to process their natural gas. These types of arrangements require us to pay the producer for the value of NGLs recovered and to redeliver the residue gas in exchange for a fixed fee. For the year ended December 31, 2004, volumes at our Houston Central Processing Plant related to this type of fee arrangement accounted for less than 0.4% of total volumes.

We also provide processing and conditioning services under contracts that contain a combination of the arrangements described above. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter during periods where such margins are in excess of an agreed-upon amount.

All of our processing agreements allow us to determine, in our sole discretion, whether we process or condition natural gas. We determine whether to process or condition the natural gas based upon the price of natural gas and various NGL products. When NGL extraction is uneconomic, NGLs are left in the natural gas stream to the maximum extent allowed by pipeline quality specifications, thus reducing the amount of fuel consumed by the processing plant and the loss in Btus resulting from the extraction of the NGLs. When we elect to condition natural gas, typically our natural gas fuel consumption volumes are reduced by approximately 79% and the Btu reduction associated with the extraction of NGLs is reduced by 94% while our average barrels of NGLs extracted from natural gas is reduced by approximately 96%. For a detailed discussion of our processing and conditioning capabilities, please read Item 1, “Business—Copano Processing.”

Our NGL Product Sales Arrangements

We use our Sheridan NGL Pipeline for transporting butane and natural gasoline mix to an interconnect with Enterprise Seminole Pipeline where we sell the butane and natural gasoline mix based on market prices for its components. At the tailgate of the plant, we deliver and sell ethane and propane to Dow Hydrocarbons and Resources Inc. at prices based on published indices, and we deliver and sell stabilized condensate to TEPPCO based on an index-related price.

Our Commercial Relationship with Kinder Morgan Texas Pipeline

For the year ended December 31, 2004, approximately 86% of the natural gas volumes processed or conditioned at our Houston Central Processing Plant were delivered to the plant through the KMTP Laredo-to-Katy pipeline while the remaining 14% were delivered directly to the plant from our gathering systems. Of the volumes delivered to the plant from the KMTP Laredo-to-Katy pipeline, approximately 23% were delivered from gathering systems controlled by us, while 77% were delivered into KMTP’s pipeline from other sources. We refer to the natural gas delivered into KMTP’s pipeline from sources other than our gathering systems as “KMTP Gas.” Of the total volume of NGLs extracted at the plant during this period, 45% originated from KMTP Gas, while 55% was attributable to gathering systems controlled by us, including our gathering systems connected directly to the plant. Under our contractual

arrangement related to KMTP Gas, we receive natural gas at our plant, process or condition the natural gas and sell the NGLs to third parties at market prices. Because the extraction of NGLs from the natural gas stream during processing or conditioning reduces the Btus of the natural gas, our arrangement with KMTP requires us to purchase natural gas at market prices to replace the loss in Btus. Pursuant to an amendment to this contract with KMTP, effective January 1, 2004, we pay a fee to KMTP based on the NGL content of the KMTP Gas only during periods of favorable processing margins. In addition, the amendment provides that during periods of unfavorable processing margins, KMTP pays us a fixed fee plus an additional payment based on the index price of natural gas.

Our Growth Strategy

Our growth strategy contemplates complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. We intend to pursue acquisitions and capital expenditure projects that we believe will allow us to capitalize on our existing infrastructure, personnel and relationships with producers and customers to provide midstream services. In the future, we intend to pursue selected acquisitions in new geographic areas, including other areas of Texas, Louisiana and the Gulf of Mexico, to the extent they present growth opportunities similar to those we are pursuing in our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms. We believe that we will have a lower cost of capital than many of our competitors that are master limited partnerships, or MLPs, because, unlike in a traditional MLP structure, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as higher per unit levels of cash distributions are received. We intend to finance future acquisitions primarily by using the capacity available under our bank credit facilities and equity or debt offerings or a combination of both. For a more detailed discussion of our capital resources, please read “—Liquidity and Capital Resources.”

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

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

Items Impacting Comparability of Our Financial Results

Our Acquisitions

Since our inception in 1992, we have grown through a combination of 25 acquisitions, including the acquisition of our Houston Central Processing Plant, and significant expansion and enhancement projects

related to our assets. Our historical acquisitions were completed at different dates and with numerous sellers and were accounted for using the purchase method of accounting. Under the purchase method of accounting, results of operations from such acquisitions are recorded in the financial statements only from the date of acquisition. As a result, our historical results of operations for the periods presented may not be comparable, as they reflect the results of operations of a business that has grown significantly due to acquisitions. For a more detailed discussion of our acquisition history, please read Item 1, “Business—General.”

Our Contract Restructuring

During the second half of 2003 and the first quarter of 2004, we restructured a number of our contracts, including our contract with KMTP, to provide that at least during periods of relatively low processing margins, we will receive supplemental fees with respect to natural gas that does not meet the downstream transporter’s gas quality specifications. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. We expect that the restructured contracts, particularly our contract with KMTP, will help reduce the volatility of our processing segment gross margin.

Our Results of Operation

	Year Ended December 31,
	2004			2003			2002
	($ in thousands)
Total gross margin	$	51,501		$	31,195		$	25,371
Operations and maintenance expenses	12,486			10,854			9,562
Depreciation and amortization	7,287			6,091			5,539
General and administrative expenses	9,217			5,849			4,177
Taxes other than income	770			926			891
Equity in (earnings) loss from unconsolidated affiliates	(419		)	127			584
Operating income	22,160			7,348			4,618
Interest and other financing costs, net	(23,075		)	(12,065		)	(6,259		)
Net loss	$	(915	)	$	(4,717	)	$	(1,641	)
Segment gross margin:
Pipelines(1)	$	30,076		$	27,551		$	18,772
Processing	21,425			3,644			6,599
Total gross margin	$	51,501		$	31,195		$	25,371
Segment gross margin per unit:
Pipelines ($/MMBtu)(1)	$	0.35		$	0.29		$	0.20
Processing:
Inlet throughput ($/MMBtu)(2)	0.10			0.02			0.03
NGLs produced ($/Bbl)(2)	3.81			1.37			1.43
Volumes:
Pipelines—throughput (MMBtu/d)(1)	239,770			256,556			264,349
Processing:
Inlet throughput (MMBtu/d)	559,939			502,057			596,520
NGLs produced (Bbls/d)	15,373			7,280			12,656
Operations and maintenance expenses:
Pipelines	$	5,813		$	5,161		$	4,049
Processing	6,673			5,693			5,513
Total operations and maintenance expenses	$	12,486		$	10,854		$	9,562

(1) Excludes results and volumes associated with our interest in Webb/Duval Gatherers. Volumes transported by Webb/Duval Gatherers were 118,873 MMBtu/d, 108,640 MMBtu/d and 89,985 MMBtu/d for the years ended December 31 2004, 2003 and 2002, respectively.

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

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Pipelines Segment Gross Margin. Pipelines segment gross margin was $30.1 million for the year ended December 31, 2004 compared to $27.6 million for the year ended December 31, 2003, an increase of $2.5 million, or 9.0%. The increase was primarily attributable to higher average natural gas prices during the year ended December 31, 2004 compared to the year ended December 31, 2003, which caused an increase in margins associated with our index price-related gas purchase and transportation arrangements. During 2004, the Houston Ship Channel, or HSC, natural gas index price averaged $5.78 per MMBtu compared to $5.24 per MMBtu during 2003, an increase of $0.54, or 10 %. Additionally, a portion of this increase was related to improved contract terms as a result of our contract restructuring efforts discussed

above, which was partially offset (i) with milder weather during the winter heating portion of the first quarter of 2004, which resulted in lower volumes being sold to utilities under high-margin arrangements and (ii) the reduction of relatively low-margin transportation volumes in the Upper Gulf Coast and Coastal Waters regions.

Processing Segment Gross Margin. Processing segment gross margin was $21.4 million for the year ended December 31, 2004 compared to $3.6 million for the year ended December 31, 2003, an increase of $17.8 million, or 494.4%. For the year ended December 31, 2004, we experienced improvements of $19.9 million in our processing segment gross margin as the result of increased plant utilization and an improved commodity price environment. For a discussion of the commodity price environment, please read “—How We Evaluate Our Operations—Segment Gross Margin”. As a result of unfavorable commodity prices in 2003, the Houston Central Processing Plant’s operations were severely curtailed during certain portions of that period. Processing segment gross margin was further improved as a result of increased conditioning fee revenue of $1.5 million for the year ended December 31, 2004 compared with the same period in 2003. This increase is attributable to receiving conditioning fee revenues for the full year of 2004 versus a partial year of receiving conditioning fee revenues in 2003. The increased processing segment gross margin was partially offset by an increase in processing upgrade payments of $3.6 million to natural gas suppliers, including our pipeline affiliates, for the year ended December 31, 2004 and was the result of increased value of processing in 2004.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $12.5 million for the year ended December 31, 2004 compared with $10.9 million for the year ended December 31, 2003, an increase of $1.6 million, or 14.7%. The increase was primarily attributable to:

· higher repair and maintenance expense totaling $0.6 million at our Houston Central Processing Plant ($0.5 million, of which $0.3 million related to painting certain facilities, replacing a cooling tower and overhauling certain engines) and in our South Texas Region ($0.1 million);

· increased utility costs at our Houston Central Processing Plant of $0.3 million related to higher plant utilization in 2004;

· a $0.3 million increase in contract maintenance services costs for our NGL line because in 2004 related reimbursements we received from a third party that shares our right-of-way were lower than reimbursements we received in 2003;

· higher environmental, health and safety expenses, measurement costs, salaries and benefits and performance awards of $0.4 million;

· increased costs of approximately $0.1 million related to the Karnes County Gathering System and Runge Gathering System that were placed in service in September 2004 and December 2004, respectively; and

· higher compression rental expense of $0.1 million in 2004 as a result of installing additional compression equipment in our South Texas and Upper Gulf Regions after December 31, 2003 offset by lower compression rental expense of $0.2 million as a result of purchasing certain compression equipment we previous leased.

Depreciation and Amortization. Depreciation and amortization totaled $7.3 million for the year ended December 31, 2004 compared with $6.1 million for the year ended December 31, 2003, an increase of $1.2 million, or 19.7%. This increase relates primarily to additional depreciation and amortization associated with capital expenditures made after December 31, 2003 including the compression equipment purchased earlier this year, the Karnes County Gathering System purchased during the third quarter of 2004 and modifications and enhancements made to the Houston Central Processing Plant during the

fourth quarter of 2003. Additionally, this increase includes $0.1 million related to pipeline and equipment retirements.

General and Administrative Expenses. General and administrative expenses totaled $9.2 million for the year ended December 31, 2004 compared with $5.8 million for the year ended December 31, 2003, an increase of $3.4 million, or 58.6%. The increase was primarily due to (i) costs of augmented infrastructure and hiring of additional staff incurred in contemplation of becoming a public company of $1.8 million, (ii) certain one-time costs related to potential alternatives to our initial public offering and management incentive payments associated with our initial public offering of $1.0 million and (iii) expenses of $0.6 million associated with costs of becoming a public company, including accounting, directors, K-1 processing, investors relations and insurance expenses.

Interest Expense. Interest and other financing costs totaled $23.2 million for the year ended December 31, 2004 compared with $12.1 million for the year ended December 31, 2003, an increase of $11.1 million, or 92%. Of this increase, $3.1 million was primarily the result of our adoption of SFAS No. 150 on July 1, 2003, which required that the value of the payment-in-kind preferred units issued to the redeemable preferred unitholders in lieu of preferred distributions be recorded as interest expense, whereas before the adoption of Statement of Financial Accounting Standard, or SFAS No. 150, this value was recorded as a direct increase to accumulated deficit. Similarly, the accretion of the allocated warrant value associated with the redeemable preferred units was also recorded as interest expense beginning July 1, 2003. Current year interest expense also included write offs totaling $9.2 million of which (i) $8.9 million related to the remaining discount and issuance costs associated with the redeemable preferred units which were redeemed using proceeds from the initial public offering and (ii) $0.3 million related to the remaining discount associated with our purchase of the warrant issued by one of our subsidiaries to the holder of the term loan. This increase was partially offset by $1.2 million of lower interest expense related to our credit facilities as a result of lower debt outstanding during the year and lower interest rates on the outstanding borrowings.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Pipelines Segment Gross Margin. Pipelines segment gross margin was $27.6 million for the year ended December 31, 2003 compared to $18.8 million for the year ended December 31, 2002, an increase of $8.8 million, or 47%.

· South Texas Region. Our South Texas Region systems experienced a significant increase in on-system volumes as well as improved contractual terms resulting in a $4.2 million increase in gross margin. Increased volumes were the result of successful producer drilling activity in our South Texas Region, as well as the full-year effect of the acquisition of our Live Oak System in May 2002. We also realized fuel savings within this region as the result of operational modifications made to our Live Oak system.

· Upper Gulf Coast Region. Gross margins from our Upper Gulf Coast Region increased $1.6 million. This increase was due both to increased natural gas sales to utilities and power generators and increased margins for sales of natural gas to these customers.

· Central Gulf Coast Region. The Central Gulf Coast Region systems experienced an increase in gross margin of $1.9 million. This increase in gross margin resulted from the renegotiation of contracts under more favorable terms and successful drilling by producers under contracts providing favorable unit margins. This increase was partially offset by a decline in throughput volumes during 2003, which was largely attributable to our discontinuing purchases of low-margin natural gas from third-party pipelines.

· Coastal Waters Region. The gross margin from our Coastal Waters Region increased by $1.1 million. This increase was the result of increased volumes as a result of the full year effect of successful drilling activity by a producer in this region.

Processing Segment Gross Margin. Processing segment gross margin was $3.6 million for the year ended December 31, 2003 compared to $6.6 million for the year ended December 31, 2002, a decrease of $3.0 million, or 45%. The decrease was primarily attributable to lower overall processing margins caused by the significant increase in natural gas prices during 2003 relative to NGL prices, which had an $8.6 million negative impact. Although we experienced an approximately 16% decrease in plant inlet volumes during 2003, this decline was largely offset by the approximate 29% increase in NGL content associated with such volumes. The reduction in NGLs recovered by the plant was attributable to the suspension of processing during portions of the year for economic reasons discussed below. The impact of lower processing margins was partially offset by:

· $2.1 million of fees collected during the third and fourth quarters of 2003 under interim processing arrangements with KMTP and many of our producers; and

· the significant benefit during the first quarter of 2003 from our suspension of processing at the Houston Central Processing Plant in reaction to a rapidly changing natural gas pricing environment resulting in approximately $3.5 million of increased processing segment gross margin during the quarter. During the final week of February 2003, our processing segment suspended processing in order to sell natural gas otherwise used by the plant for fuel and hydrocarbon shrinkage requirements at spot prices ranging from $6.55 to $24.88 per MMBtu, a significant increase from the February monthly index of $5.44 per MMBtu. Management estimates that this activity improved processing gross margins by approximately $1.5 million for the month. Our suspension of processing operations continued in the beginning of March 2003 because the March HSC index price of $8.79 per MMBtu rendered processing uneconomic. Commencing March 11, 2003, we were able to purchase natural gas at spot prices ranging from $4.87 to $6.57 per MMBtu, enabling us to resume processing on that date. These lower gas prices made processing profitable for the balance of the month. Management estimates that these circumstances improved our processing segment gross margin by approximately $2.0 million for March 2003.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $10.9 million for the year ended December 31, 2003 compared with $9.6 million for the year ended December 31, 2002, an increase of $1.3 million, or 14%. The increase was primarily attributable to (1) an increase of $0.2 million of costs associated with operating our Live Oak System for the full year 2003 as opposed to only eight months during 2002, (2) additional costs of $0.5 million associated with installing additional leased compression equipment on our Copano Bay System, Live Oak System, Mesteña Grande System and Agua Dulce System to support increased natural gas throughput or enhanced service on these systems, (3) increased costs of $0.3 million for our Copano Bay System related to repair, maintenance and insurance costs and (4) an increase of $0.3 million at our Houston Central Processing Plant primarily attributable to insurance costs.

Depreciation and Amortization. Depreciation and amortization totaled $6.1 million for the year ended December 31, 2003 compared with $5.5 million for the year ended December 31, 2002, an increase of $0.6 million, or 11%. This increase was primarily attributable to (1) a $0.5 million increase related to the full year impact of capital expenditures made in 2002 at our Houston Central Processing Plant and depreciation of asset enhancement expenditures made in 2003 to our Copano Bay System and Agua Dulce System and (2) a $0.1 million increase related to a full year of depreciation being recognized during 2003 associated with our Live Oak System, which was acquired during May 2002.

General and Administrative Expenses. General and administrative expenses totaled $5.8 million for the year ended December 31, 2003 compared with $4.2 million for the year ended December 31, 2002, an

increase of $1.6 million, or 38%. The increase was primarily due to costs of augmented infrastructure ($0.7 million), the hiring of additional staff ($0.7 million) and the establishment of a reserve for uncollectible receivables ($0.2 million).

Interest Expense. Interest and other financing costs totaled $12.1 million for the year ended December 31, 2003 compared with $6.4 million for the year ended December 31, 2002, an increase of $5.7 million, or 89%. This increase was primarily a result of our July 1, 2003 adoption of SFAS No. 150. Additional interest was also accrued with respect to the senior secured subordinated indebtedness of our processing segment. This increase was partially offset by lower bank debt outstanding during the year coupled with lower interest rates on our outstanding bank borrowings.

General Trends and Outlook

Our pipeline segment gross margins are influenced by the price of natural gas and drilling activity in our operating regions. Increases in natural gas prices have a positive impact on our pipeline margins and conversely, a reduction in natural gas prices negatively impacts our pipeline segment gross margins. On average, natural gas prices for the last half of 2004 have trended upward, and full-year 2004 average natural gas prices were higher than those in the first half of 2004. Natural gas prices for the first three months of 2005 have been higher than the average full-year price in 2004. Volumes of natural gas on our pipelines also impact our pipeline segment gross margins. Increases in volumes gathered or transported positively impact our pipeline segment gross margins and conversely, reductions in volumes gathered or transported negatively impact our pipeline segment gross margins. Higher natural gas prices typically encourage drilling activity in our operating regions. We believe that natural gas prices will continue to fluctuate over the next twelve months and are likely to remain higher than the 2004 full-year average.

Our processing segment gross margins are influenced by the price of NGLs in relation to natural gas prices, and the supply of NGLs contained in natural gas delivered to us at our Houston Central Processing Plant. Increases in NGL prices, relative to natural gas prices, have a positive impact on our processing segment gross margins and, conversely, a reduction in NGL prices, relative to natural gas prices, negatively impacts our processing segment gross margins. On average, NGL prices, relative to natural gas prices, for the last half of 2004 trended upward and full-year 2004 NGL prices, in relation to natural gas prices, were higher than those in the first half of 2004. NGL prices in relation to natural gas prices for the first three months of 2005 have been above the full-year average price in 2004. The supply of NGLs contained in natural gas delivered to us at our Houston Central Processing Plant also impacts our processing segment gross margins. Increases in the supply of NGLs contained in the natural gas delivered to our plant positively impact our processing segment gross margins if the price of NGLs exceeds the cost of the natural gas required to extract such NGLs. Conversely, reductions in the supply of NGLs negatively impact our processing segment gross margins under such circumstances. We believe that NGL prices, relative to natural gas prices, will continue to fluctuate, but at levels generally above historical averages, for full-year 2005.

In addition to operating and maintenance expenses, general and administrative expenses and maintenance capital expenditures, our distributable cash flow is impacted by the interest expense we pay on our indebtedness. Currently, interest rates on our outstanding borrowings fluctuate based on reserve-adjusted interbank offered market rates. Increases in interest rates have a negative impact on our distributable cash flow, and, conversely, decreases in interest rates have a positive impact on distributable cash flow. Interest rates for the last nine months of 2004 and the first three months of 2005 have trended upwards. We believe that interest rates will continue to rise for the remainder of 2005.

Impact of Inflation

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

Liquidity and Capital Resources

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

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of December 31, 2004.

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

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

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

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

During the year ended December 31, 2004, our capital expenditures totaled $8.9 million, consisting of $7.1 million of expansion capital and $1.8 million of maintenance capital. The majority of the expansion capital expenditures relate to the purchase of compressor units that we previously leased and the acquisition and integration of our Karnes County Gathering System and our Runge Gathering System. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our credit facilities and the issuance of additional equity or debt as appropriate given market conditions. We anticipate expending $3.0 million to $4.0 million of maintenance capital over the next 12 months.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2004, is as follows:

	Payment Due by Period
Type of Obligation	Total Obligation			Within 1 Year			2-3 Years		4-5 Years		More than 5 years
	(In thousands)
Long-term debt		$	57,000		$	—	$	9,000	$	48,000		$	—
Interest		8,741			2,653		5,683		405			—
Operating Leases		2,305			670		804		688			143
Total contractual cash obligations		$	68,046		$	3,323	$	15,487	$	49,093		$	143

In addition to the contractual obligations noted in the table above, we have both fixed and variable contracts to purchase natural gas, which were executed in connection with our natural gas marketing activities. As of December 31, 2004, we had fixed contractual commitments to purchase 364,250 MMBtu of natural gas in January 2005. All of these contracts were based on index-related prices. Using these index-related prices at December 31, 2004, we had total commitments to purchase $2.1 million of natural gas under such agreements. Our contracts to purchase variable quantities of natural gas at index-related prices range from one month to the life of the dedicated production. During December 2004, we purchased 4,591,203 MMBtu of natural gas under such contracts.

For a discussion of our real property leases, please read Item 1, “Business—Office Facilities.”

Cash Flows.

The following summarizes our cash flows for each of the three years ended December 31, 2004, as reported in the historical consolidated statements of cash flows found in Item 8 of this Annual Report.

	Year Ended December 31,
	2004			2003			2002
	(In thousands)
Net cash provided by operating activities	$	17,697		$	15,296		$	8,865
Net cash used in investing activities	(8,920		)	(6,192		)	(16,817		)
Net cash used in financing activities	(6,369		)	(9,633		)	(2,591		)
Net increase (decrease) in cash and cash equivalents	2,408			(529		)	(10,543		)
Cash and cash equivalents at beginning of year	4,607			5,136			15,679
Cash and cash equivalents at end of year	$	7,015		$	4,607		$	5,136

Operating: For the year ended December 31, 2004, operating cash flows of $17.7 million reflects the net loss of $0.9 million and the following non-cash items: depreciation and amortization of $9.3 million, payment-in-kind interest on redeemable preferred units of $6.5 million, accretion and early extinguishment of preferred unitholders warrant value of $9.4 million, payment-in-kind interest and accretion related to subordinated debt of $1.2 million, equity earnings of unconsolidated affiliate of $0.4 million, and working capital decreases of $7.4 million.

For the year ended December 31, 2003, operating cash flows of $15.3 million reflect a net loss of $4.7 million and the following non-cash items: depreciation and amortization of $7.0 million, payment-in-kind interest on subordinated debt of $3.9 million, payment-in-kind interest on redeemable preferred units of $3.5 million, accretion of preferred unitholders warrant value of $0.8 million, equity losses of unconsolidated affiliate of $0.1 million and working capital increases of $4.7 million.

The overall increase of $2.4 million in operating cash flow for the year ended December 31, 2004 compared to the year ended December 31, 2003 was primarily the result of a decrease in net loss and non-cash items itemized above of $14.7 million and a decrease in the changes in working capital components

(exclusive of cash and cash equivalents) of $12.3 million. This decrease in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of decreased accounts payable as a result of the resolution of a dispute between a royalty owner and an operator from which we purchase natural gas. As a result of the dispute, we had suspended payments to the operator. Upon receiving notice that the parties had substantially resolved their dispute, we used additional cash during the second quarter of 2004 when we released approximately $6.1 million in suspended funds to pay the operator for natural gas we had purchased during 2002, 2003 and early 2004.

For the year ended December 31, 2002, operating cash flows of $8.9 million reflect a net loss of $1.6 million and the following non-cash items: depreciation and amortization of $6.0 million, payment-in-kind interest on subordinated debt of $3.3 million, equity losses of unconsolidated affiliate of $0.6 million and working capital increases of $0.6 million.

The overall increase of $6.4 million in operating cash flow from 2002 to 2003 was primarily the result of changes in net loss and non-cash items itemized above of $2.3 million and an increase in working capital of $4.1 million. This increase in working capital was primarily a result of an increase in accounts payable related to suspended payments to a well operator from whom we purchase natural gas, after receiving notification that a royalty interest owner had sued the operator. Standard industry practice and contractual obligations required us to suspend payment to the operator until we received notification that the dispute between the operator and the royalty owner had been resolved. As a result, our accounts payable increased from 2002 to 2003 because we continued to purchase natural gas from the operator, but had suspended payment to the operator for these purchases. We received notification of partial settlement in the second quarter of 2004 at which time we paid the producer for the majority of the suspended amounts.

Investing: Net cash used in investing activities was $8.9 million, $6.2 million and $16.8 million for the years ended December 31, 2004, 2003 and 2002, respectively. Capital expenditures for additions to property, plant and equipment and acquisitions were:

· $8.9 million in 2004, which includes capital expenditures for the acquisition of compression equipment, the Karnes County Gathering System and the Runge Gathering System as well as the continued development of our SCADA system.

· $6.2 million in 2003, which includes capital expenditures for the modification to our Houston Central Processing Plant and the development of our SCADA system; and

· $16.8 million in 2002, which includes $13.1 million of capital expenditures for our acquisition of the Live Oak system, the construction of a pipeline connecting our Agua Dulce System with the Webb/Duval Gathering System, the installation of new and expansion of existing compressor stations and the performance of upgrades to our Houston Central Processing Plant, as well as $3.7 million for the purchase of additional partnership interests in Webb/Duval Gatherers.

Financing: Net cash used in financing activities was $6.4 million, $9.6 million and $2.6 million for the years ended December 31, 2004, 2003 and 2002, respectively. Cash used in financing activities for the year ended December 31, 2004, exclusive of our initial public offering proceeds, included net borrowings of long-term debt prior to our initial public offering of $3.5 million reduced by payments related to

· cash distributions paid to the pre-offering common and preferred unitholders of $4.0 million,

· $3.4 million of offering costs, and

· debt financing related costs of $2.5 million.

We received net proceeds from our initial public offering, including proceeds from the exercise of the underwriters’ over-allotment option, of $106.95 million after deducting underwriting commissions and discounts. We used these proceeds to

· redeem our redeemable preferred units from pre-offering investors for $78.1 million,

· reduce existing indebtedness under our Copano Pipelines credit agreement, discussed below, by $6.0 million,

· reduce the overall existing indebtedness of our Copano Processing segment, discussed below, by $7.0 million,

· redeem common units from certain existing investors for $13.95 million,

· pay other obligations of $1.0 million, and

· pay certain additional expenses of our initial public offering of $0.9 million.

For the year ended December 31, 2003, cash used in financing activities was primarily attributable to our net repayment of $7.8 million in long-term debt, $0.8 million of offering costs, $0.8 million of cash distributions paid to our preferred unitholders and $0.2 million of debt issue costs and the repayment of other long-term obligations.

For the year ended December 31, 2002, net cash used in financing activities primarily resulted from cash distributions paid to the pre-offering common and preferred unitholders.

Description of Our Indebtedness

Copano Pipelines Credit Agreement

Copano Pipelines Group, L.L.C. (“CPG”), a wholly owned subsidiary, and certain of Copano Pipelines’ operating subsidiaries have a $100.0 million revolving credit agreement (the “CPG Credit Agreement”), which matures on February 12, 2008. As of December 31, 2004, $48.0 million was outstanding under this revolving credit facility, bearing interest at a weighted average interest rate of 5.416%. We used $6.0 million of the proceeds from our initial public offering in November 2004 to reduce the amount outstanding under this facility to $48.0 million. In March 2005, we reduced the balance outstanding under the CPG Credit Agreement to $45.0 million.

Future borrowings under this revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. This revolving credit facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders. This credit facility is available to be drawn on and repaid without restriction so long as CPG is in compliance with the terms of the CPG Credit Agreement, as amended, including certain financial covenants.

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

Agreement also contains covenants, which, among other things, require CPG and certain of Copano Pipelines’ operating subsidiaries to maintain specified ratios or conditions as follows:

· EBITDA (as defined) to interest expense of not less than 3.5 to 1.0;

· total debt to EBITDA of not more than 4.5 to 1.0;

· total senior debt to EBITDA of not more than 3.75 to 1.0;

· minimum tangible net worth; and

· positive net working capital (excluding current debt maturities)

Based upon the senior debt to EBITDA ratio calculated as of December 31, 2004 (utilizing trailing four quarters’ EBITDA), CPG had approximately $24.8 million of unused capacity under the CPG Credit Agreement.

The obligations under this revolving credit facility are secured by first priority liens on substantially all of the assets of Copano Pipelines and its subsidiaries (other than certain subsidiaries with insignificant assets) and our interest in Copano Pipelines. Additionally, the obligations under the revolving credit facility are guaranteed by us and Copano Pipelines and its subsidiaries (other than certain subsidiaries with insignificant assets).

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

Our management believes that CPG and its subsidiaries were in compliance with the terms of the CPG Credit Agreement as of December 31, 2004. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

· failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

· failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

· default by us on the payment of any other indebtedness in excess of $0.5 million, or any default 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;

· the entry, and failure to pay, one or more adverse judgments in excess of $0.5 million against which enforcement proceedings are brought or that are not stayed pending appeal; and

· a change of control (as defined in the credit agreement).

CHC Facility

Prior to our initial public offering, we financed our processing operations through a $35 million revolving credit facility, which was repaid in February 2004, as well as through a $21.2 million term loan entered into in August 2001 (discussed in Note 7 to the Consolidated Financial Statements contained in Item 8 of this Annual Report). The term loan would have matured on August 14, 2008 and bore interest at a rate of 14%. In November 2004 concurrent with the closing of our initial public offering, we used $7.0 million of the proceeds from our initial public offering to reduce this balance.

In November 2004, concurrently with the closing of our initial public offering, Copano Houston Central, L.L.C. (“CHC”), a wholly owned subsidiary, and the Copano Processing operating subsidiaries established a $12.0 million revolving credit facility (the “CHC Facility”). Approximately $9.0 million was drawn under this facility concurrently with the closing of our initial public offering to retire in full the term loan and the balance is available to be drawn under the CHC Facility to finance capital expenditures (including construction and expansion projects) as well as to meet working capital requirements of our processing operations. The CHC Facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered available cash or operating surplus distributable to our unitholders. As of December 31, 2004, $9.0 million was outstanding under this revolving credit facility, bearing interest at a weighted average interest rate of 4.77%. In March 2005, we reduced the balance outstanding under the CHC Facility to $8.0 million.

At CHC’s election, interest under the CHC Facility is determined by reference to (1) the reserve-adjusted interbank offered rate, or IBOR, plus an applicable margin between 2.5% and 3.5% per annum or (2) the prime rate plus, in certain circumstances, an applicable margin of up to 1.5% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for IBOR loans, except that if the interest period for an IBOR loan is six months, interest will be paid at the end of each three-month period. For additional information regarding restrictions and covenants under this credit agreement, please read Note 7 to the Consolidated Financial Statements contained in Item 8 of this Annual Report.

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

The CHC Facility contains various covenants that limit the ability of CHC and its subsidiaries to:

· incur indebtedness;

· grant certain liens;

· make certain loans, acquisitions and investments;

· make distributions if a default or event of default exists;

· change their capital structure;

· merge or consolidate; or

· sell all or any material part of their assets.

The CHC Facility also contains covenants, which, among other things, require CHC to maintain specified ratios or conditions as follows:

· EBITDA (as defined in the credit agreement) to interest expense of not less than 3.25 to 1.0;

· total senior debt to EBITDA of not more than 3.5 to 1.0 at closing, reducing to not more than 2.75 to 1.0 over the two-year term of the loan;

· positive net working capital (excluding current debt maturities);

· minimum tangible net worth;

· make maintenance capital expenditures of not more than $2.5 million per calendar year; and

· maintain an interest reserve account of at least $1.0 million.

Our management believes that CHC and its subsidiaries were in compliance with the covenants under this facility as of December 31, 2004. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

· failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

· failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

· default by us or any of our subsidiaries on the payment of any other indebtedness in excess of $0.5 million, default by CHC or any of its subsidiaries on the payment of any other indebtedness in excess of $0.25 million, or, in either case, any default 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;

· the entry, and failure to pay, one or more adverse judgments in excess of (a) $0.5 million in the case of judgments against us or (b) $0.25 million in the case of judgments against CHC or any of its subsidiaries, and, in each case, against which enforcement proceedings are brought or that are not stayed pending appeal;

· a change of control (as defined in the CHC Facility); and

· any payment default by any guarantor of its obligations under this revolving credit facility or revocation of any guaranty.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board, or FASB, issued SFAS No. 123 (revised 2004), or SFAS No. 123(R), “Share Based Payment” which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principles Board, or APB, Opinion No. 25 and generally requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). The standard also requires us to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. We are required to apply SFAS No. 123(R) to all awards granted, modified or settled in the first reporting period after June 15, 2005. We are also required to use either the

“modified prospective method” or the “modified retrospective method.” Under the modified prospective method, we must recognize compensation cost for all awards granted after we adopt the standard and for the unvested portion of previously granted awards that are outstanding on that date. Under the modified retrospective method, we must restate previously issued financial statements to recognize the amounts we previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. See Note 2 to the Consolidated Financial Statements contained in Item 8 of this Annual Report. Under both methods, we are permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption. We have commenced the analysis of the impact of SFAS 123(R), but have not yet decided: (1) whether we will elect early adoption, (2) if we elect early adoption, at what date we would do so, (3) whether we will use the modified prospective method or elect to use the modified retrospective method, and (4) whether we will elect to use straight line amortization or an accelerated method. Additionally, we cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption. Accordingly, we cannot currently quantify with precision the effect that this standard would have on our financial position or results of operations in the future, except that we probably will recognize a greater expense for any awards that we may grant in the future than we would using the current guidance.

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

Significant 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, you should read Notes 2 and 3 to the Consolidated Financial Statements contained in Item 8 in this Annual Report.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS No. 150 requires that certain financial instruments previously classified as equity be classified as liabilities or, in some cases, as assets. We adopted SFAS No. 150 effective July 1, 2003 and classified our redeemable preferred units as a liability and recorded the value of the paid-in-kind, or PIK, preferred unit distributions issued to the redeemable preferred unitholders as interest expense, whereas prior to the adoption of SFAS No. 150, these distributions were recorded as a direct reduction of the accumulated deficit. Additionally, the accretion of the allocated value assigned to the warrants held by the holders of the redeemable preferred units was recorded as interest expense upon adoption of SFAS No. 150 whereas previously this accretion was recorded as a direct reduction of paid-in-capital. Please read Notes 3 and 9 to our Consolidated Financial Statements contained in Item 8 in this Annual Report.

Impairment of Long-Lived Assets. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we evaluate the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. Estimating the fair value for the assets to determine if impairment has occurred, and recording a provision for loss if the carrying value is greater than fair value, determine the amount of the impairment recognized. 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 and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas 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 regions in which our products are located;

· the availability and prices of raw natural gas supply;

· our ability to negotiate favorable sales agreements;

· 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.

Asset Retirement Obligation. SFAS No. 143, Accounting for Asset Retirement Obligations requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which the obligation is incurred and can be reasonably estimated. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard was effective for us on January 1, 2003. Under the implementation guidelines of SFAS No. 143, we have reviewed our long-lived assets for asset retirement obligation, or ARO, liabilities and identified any such liabilities. These liabilities include ARO liabilities related to (i) right-of-way easements over property not owned by us, (ii) leases of certain currently operated facilities and (iii) regulatory requirements triggered by the abandonment or retirement of certain of these assets. As a result of our analysis of identified AROs, we are not required to recognize such potential liabilities. Our rights under our easements are renewable or perpetual and retirement action, if any, is only required upon nonrenewal or abandonment of the easements. We currently expect to continue to use or renew all such easement agreements and to use these properties for the foreseeable future. Similarly, under certain leases of currently operated facilities, retirement action is only required upon termination of these leases and we do not expect termination in the foreseeable future. Accordingly, management is unable to reasonably estimate and record liabilities for our obligations that fall under the provisions of SFAS No. 143 because it does not believe that any of the applicable assets will be retired or abandoned in the foreseeable future. We will record AROs in the period in which the obligation may be reasonably estimated.

Equity Method of Accounting. Although we own a 62.5% partnership interest in Webb/Duval Gatherers, we account for the investment using the equity method of accounting since the minority general partners of Webb/Duval Gatherers have substantive participating rights with respect to the management of Webb/Duval Gatherers.

Revenue Recognition. Our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing. Transportation, compression and processing-related revenues are recognized in the period when the service is provided.

Forward-Looking Statements

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

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

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

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

· Our ability to retain our key producers;

· Our ability to retain our key customers;

· General economic conditions;

· The effects of government regulations and policies; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this Annual Report, including without limitation in conjunction with the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Annual Report “—Risk Factors.” All forward-looking statements included in this Annual Report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive.

Risks Related to Our Business

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

· Our success depends upon our ability to continually obtain new sources of natural gas supply, and any decrease in supplies of natural gas could reduce our ability to make distributions to our unitholders.

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

· We depend on certain key producers for a significant portion of our supply of natural gas, and the loss of any of these key producers could reduce our supply of natural gas transported on our pipeline systems and could result in a decline in our revenues and cash available for distribution.

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

· We depend on certain key customers for sales of natural gas and NGLs. To the extent these and other customers reduce the volumes of natural gas and NGLs they purchase from us, our revenues and cash available for distribution could decline.

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

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

· Compliance with pipeline integrity regulations issued by the Texas Railroad Commission could result in substantial expenditures for testing, repairs and replacement.

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

· If we do not make acquisitions on economically acceptable terms, our future growth and ability to increase distributions will be limited.

· Expanding our business by constructing new assets subjects us to risks that the project may not be completed on schedule, the costs associated with the project may exceed our expectations and additional natural gas supplies may not be available following completion of the project, which could cause our revenues and cash available for distribution to be less than anticipated.

· If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of way increases, then we may be unable to fully execute our growth strategy, which may have an adverse impact on our ability to increase distributions to our unitholders.

· 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.

· Restrictions in our subsidiaries’ credit facilities limit their ability to borrow additional funds and may limit their ability to make distributions to us, which may limit our ability to make distributions to our unitholders and capitalize on acquisitions and other business opportunities.

· Due to our lack of asset diversification, adverse developments in our gathering, treating, processing and transportation businesses would reduce our ability to make distributions to our unitholders.

Risks Related to Our Structure

· Affiliates of our management, CSFB Private Equity and EnCap Investments controlled, in the aggregate, a 24.14% interest in us as of December 31, 2004. Our management, CSFB Private Equity or EnCap Investments may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to unitholders in the event unitholders have a claim based on conflicts of interest.

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

· Escrows established by our pre-offering investors and distributions attributable to the common units and subordinated units held by our pre-offering investors immediately prior to our initial public offering may be insufficient to reimburse us for all of our general and administrative expenses in excess of the cap, which could materially reduce the cash available for distribution to our unitholders.

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

· Affiliates of our management, CSFB Private Equity or EnCap Investments may sell units or other limited liability company interests in the trading market, which could reduce the market price of our outstanding common units.

· Reimbursements paid to one of our affiliates will reduce the amount of our available cash on hand at the end of each quarter, and, therefore, reduce the amount of cash that we can distribute to our unitholders.

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 entity-level taxation by individual states. If the IRS treats us as a corporation for tax purposes or we become subject to entity-level taxation, it would substantially reduce the amount of cash available for distribution to our unitholders.

· A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the costs of any contest will reduce cash available for distribution to our unitholders.

· A unitholder may be required to pay taxes on income from us even if the unitholder does not receive any cash distributions from us.

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. The principal market risk to which we are exposed is commodity price risk for natural gas and NGLs. We also incur, to a lesser extent, risks related to interest rate fluctuations. We do not engage in commodity energy trading activities.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our revolving credit facilities, which had an average floating interest rate of 5.3% as of December 31, 2004. We had a total of $57.0 million of indebtedness outstanding under our credit facilities as of December 31, 2004. The impact of a 1% increase in interest rates on this amount of debt would result in an increase in interest expense and a corresponding decrease in net income of approximately $0.6 million annually.

Commodity Price Risks. Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. The current mix of our contractual arrangements described above, together with our ability to condition natural gas during periods of unfavorable processing margins, significantly reduces our exposure to natural gas and NGL price volatility. Natural gas prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services. For the year ended December 31, 2004, the impact on our gross margin of a $0.01 per gallon change (increase or decrease) in NGL prices would directly result in a change of $1.8 million to our gross margin and the impact on our gross margin of a $0.10 per MMBtu increase (decrease) in the price of natural gas would result in a decrease (increase) of $1.5 million to our gross margin Increases in natural gas prices or reduced natural gas liquids prices could trigger favorable provisions under our restructured processing agreement, which is expected to reduce our exposure to adverse processing margins. If processing margins are negative, we can operate the plant in a conditioning mode such that additional price increases in natural gas would have an anticipated positive impact to our gross margin.

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

Item 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-49 of this Annual Report and are incorporated herein by reference.

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

None.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2004			2003			2002
	(in thousands)
Cash Flows From Operating Activities:
Net loss	$	(915	)	$	(4,717	)	$	(1,641	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	7,287			6,091			5,539
Amortization of debt issue costs	2,000			940			531
Equity in (earnings) loss from unconsolidated affiliate	(419		)	127			584
Payment-in-kind interest on subordinated debt	814			3,908			3,286
Payment-in-kind interest to preferred unitholders	6,508			3,446			—
Accretion of preferred unitholders warrant value	9,405			781			—
Accretion of subsidiary warrant value	405			—			—
Deferred compensation	53			—			—
Deferred rent	(59		)	—			—
Deferred revenue	(2		)	—			—
(Increase) decrease in:
Accounts receivable	(11,440		)	(1,150		)	(7,517		)
Accounts receivable from affiliates	(370		)	(504		)	678
Interest receivable from affiliates	85			—			—
Prepayments and other current assets				162			(699		)
Increase (decrease) in:
Accounts payable	5,591			5,101			8,313
Accounts payable to affiliates	(1,244		)	439			(158		)
Other current liabilities	(2		)	672			(51		)
Net cash provided by operating activities	17,697			15,296			8,865
Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangible assets	(8,590		)	(6,054		)	(9,578		)
Acquisitions of property, plant and equipment	(330		)	(138		)	(3,526		)
Investment in unconsolidated affiliate	—			—			(3,858		)
Distributions from unconsolidated affiliate	—			—			145
Net cash used in investing activities	(8,920		)	(6,192		)	(16,817		)
Cash Flows From Financing Activities:
Repayments of long-term debt	(34,313		)	(21,800		)	(5,100		)
Proceeds from long-term debt	40,000			14,000			5,200
Escrow cash	1			(1		)	—
Repayment of subordinated debt	(15,199		)	—			—
Repayments of other long-term obligations	(991		)	(89		)	(103		)
Deferred financing costs	(2,063		)	(135		)	(107		)
Payment of subscription receivable	143			—			—
Distributions to special unitholders	(143		)	—			—
Distributions to common unitholders	(4,000		)	—			(287		)
Proceeds from initial public offering of common units, net of underwriting discounts and commissions of $8,050	106,950			—			—
Payment of offering costs	(4,322		)	(798		)	—
Redemption of preferred units	(78,077		)	—			—
Distributions to preferred unitholders	—			(810		)	(2,194		)
Redeem common units	(13,950		)	—			—
Purchase warrants issued by subsidiary	(405		)	—			—
Net cash used in financing activities	(6,369		)	(9,633		)	(2,591		)
Net increase (decrease) in cash and cash equivalents	2,408			(529		)	(10,543		)
Cash and cash equivalents, beginning of year	4,607			5,136			15,679
Cash and cash equivalents, end of year	$	7,015		$	4,607		$	5,136

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

	Common						Subordinated					Common Special							Junior						Junior Special
	Number of Units			Common Units			Number of Units		Subordinated Units			Number of Units			Common Special Units				Number of Units			Junior Units			Number of Units			Junior Special Units
	(In thousands)
Balance, December 31, 2001		1,299		$	3,471			—		$	—		—			$	—			620		$	526			—			$	—
Payment-in-kind preferred distributions		—		—				—		—			—			—				—		—				—			—
Accretion of preferred units		—		—				—		—			—			—				—		—				—			—
Distributions to preferred unitholders		—		—				—		—			—			—				—		—				—			—
Distributions to common unitholder		—		—				—		—			—			—				—		—				—			—
Issuance of common and junior special units		—		—				—		—			54			54				—		—				18			9
Subscription receivable		—		—				—		—			—			—				—		—				—			—
Net loss		—		—				—		—			—			—				—		—				—			—
Change in fair value of derivatives used for hedging purposes		—		—				—		—			—			—				—		—				—			—
Comprehensive loss
Balance, December 31, 2002		1,299		3,471				—		—			54			54				620		526				18			9
Equity issuance costs (See Note 9)		—		—				—		—			—			—				—		—				—			—
Payment-in-kind preferred distribution		—		—				—		—			—			—				—		—				—			—
Accretion of preferred units		—		—				—		—			—			—				—		—				—			—
Distributions to preferred unitholders		—		—				—		—			—			—				—		—				—			—
Issuance common and junior special units		—		—				—		—			100			100				—		—				40			20
Subscription receivable		—		—				—		—			—			—				—		—				—			—
Net loss		—		—				—		—			—			—				—		—				—			—
Change in fair value of derivatives used for hedging purposes		—		—				—		—			—			—				—		—				—			—
Comprehensive loss
Balance, December 31, 2003		1,299		3,471				—		—			154			154				620		526				58			29
Subscription receivable		—		—				—		—			—			—				—		—				—			—
Distribution to special unitholders		—		—				—		—			—			(121		)		—		—				—			(22		)
Distribution to pre-Offering unitholders		—		—				—		—			—			—				—		—				—			—
Unit exchange		739		2,540				3,519		10,379			(154	)		(33		)		(620	)	(526		)		(58	)		(7		)
Issuance of common units to public		5,750		115,000				—		—			—			—				—		—				—			—
Offering costs		—		(13,170		)		—		—			—			—				—		—				—			—
Redeem common units from certain pre-Offering unitholders		(750	)	(13,950		)		—		—			—			—				—		—				—			—
Issuance of restricted units		18		434				—		—			—			—				—		—				—			—
Stock-based compensation		—		—				—		—			—			—				—		—				—			—
Net loss		—		—				—		—			—			—				—		—				—			—
Comprehensive loss
Balance, December 31, 2004		7,056		$	94,325			3,519		$	10,379		—			$	—			—		$	—			—			$	—

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

F-6

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL AND COMPREHENSIVE LOSS (Continued)

	Paid-in Capital			Accumulated Earnings (Deficit)				Subscription Receivable				Deferred Compensation				Other Comprehensive Loss				Total			Total Comprehensive Income (Loss)
	(In thousands)
Balance, December 31, 2001	$	11,095			$	1,065			$	—			$	—			$	—		$	16,157			$	—
Payment-in-kind preferred distributions	—				(3,853		)		—				—				—			(3,853		)		—
Accretion of preferred units	—				(1,379		)		—				—				—			(1,379		)		—
Distributions to preferred unitholders	—				(2,194		)		—				—				—			(2,194		)		—
Distributions to common unitholder	—				(287		)		—				—				—			(287		)		—
Issuance of common and junior special units	—				—				—				—				—			63				—
Subscription receivable	—				—				(63		)		—				—			(63		)		—
Net loss	—				(1,641		)		—				—				—			(1,641		)		(1,641		)
Change in fair value of derivatives used for hedging purposes	—				—				—				—				(226		)	(226		)		(226		)
Comprehensive loss																								$	(1,867	)
Balance, December 31, 2002	11,095				(8,289		)		(63		)		—				(226		)	6,577				—
Equity issuance costs (See Note 9)	1,258				—				—				—				—			1,258				—
Payment-in-kind preferred distribution	—				(2,453		)		—				—				—			(2,453		)		—
Accretion of preferred units	—				(743		)		—				—				—			(743		)		—
Distributions to preferred unitholders	—				(810		)		—				—				—			(810		)		—
Issuance common and junior special units	—				—				—				—				—			120				—
Subscription receivable	—				—				(120		)		—				—			(120		)		—
Net loss	—				(4,717		)		—				—				—			(4,717		)		(4,717		)
Change in fair value of derivatives used for hedging purposes	—				—				—				—				226			226				226
Comprehensive loss																								$	(4,491	)
Balance, December 31, 2003	12,353				(17,012		)		(183		)		—				—			(662		)		—
Subscription receivable	—				—				183				—				—			183				—
Distribution to special unitholders	—				—				—				—				—			(143		)		—
Distribution to pre-Offering unitholders	—				(4,000		)		—				—				—			(4,000		)		—
Unit exchange	(12,353		)		—				—				—				—			—				—
Issuance of common units to public	—				—				—				—				—			115,000				—
Offering costs	—				—				—				—				—			(13,170		)		—
Redeem common units from certain pre-Offering unitholders	—				—				—				—				—			(13,950		)		—
Issuance of restricted units	—				—				—				(434		)		—			—				—
Stock-based compensation	—				—				—				13				—			13				—
Net loss	—				(915		)		—				—				—			(915		)		(915		)
Comprehensive loss																								$	(915	)
Balance, December 31, 2004	$	—			$	(21,927	)		$	—			$	(421	)		$	—		$	82,356

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

F-7

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

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

CE, through its wholly owned subsidiaries, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in the South Texas and Texas Gulf Coast regions (CE and its subsidiaries are collectively referred to as the “Company”). The Company’s natural gas pipelines collect natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Company’s gas processing plant, utilities and industrial consumers. Natural gas shipped to the Company’s gas processing plant, either on the Company’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into mixed natural gas liquids, or NGLs, and then fractionated or separated into selected component NGL products, including ethane, propane, butane and natural gasoline mix and stabilized condensate. The Company also owns an NGL products pipeline extending from the Company’s gas processing plant to the Houston area. The Company refers to its natural gas pipeline operating subsidiaries collectively as “Copano Pipelines” and to its processing and related activities operating subsidiaries collectively as “Copano Processing”.

Copano Pipelines Group, L.L.C. (“CPG”), a Delaware limited liability company and wholly owned subsidiary of CE, owns directly or indirectly all the entities comprising Copano Pipelines, with the exception of Copano/Webb-Duval Pipeline, L.P. (“CWDPL”), which was conveyed to CE in February 2004. Copano Pipelines entities include the following:

· Copano Energy Services/Upper Gulf Coast, L.P.

· Copano Energy Services/Texas Gulf Coast, L.P.

· Copano Field Services/Agua Dulce, L.P. (“Agua Dulce”)

· Copano Field Services/Central Gulf Coast, L.P. (“CFS/CGC”)

· Copano Field Services/Copano Bay, L.P.

· Copano Field Services/Live Oak, L.P. (“CFS/LO”)

· Copano Field Services/South Texas, L.P.

· Copano Field Services/Karnes, L.P. (“CFS/Karnes”)

· Copano Field Services/Upper Gulf Coast, L.P.

· Copano Pipelines/Hebbronville, L.P. (“Hebbronville”)

· Copano Pipelines/South Texas, L.P.

· Copano Pipelines/Texas Gulf Coast, L.P.

· Copano Pipelines/Upper Gulf Coast, L.P.

· Copano/Webb-Duval Pipeline, L.P.

F-8

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 1—Organization (Continued)

Copano Houston Central, L.L.C. (“CHC”), a Delaware limited liability company and a wholly owned subsidiary of CE, owns directly or indirectly all the entities comprising Copano Processing which include Copano Processing, L.P. and Copano NGL Services, L.P.

On November 15, 2004, the Company completed its initial public offering (the “Offering”) of 5,750,000 common units, inclusive of 750,000 common units that were issued as a result of the underwriters’ exercise of their over-allotment option. The common units issued in the Offering were sold at $20.00 per common unit and the net proceeds from the Offering (other than from the underwriters’ exercise of their over-allotment option) were used (i) to redeem CE’s redeemable preferred units from pre-Offering investors for $78,077,000 (see Note 9), (ii) to reduce existing indebtedness under the CPG Credit Agreement by $6,000,000 (see Note 7), (iii) to reduce existing indebtedness under the Tejas Credit Agreement by $7,000,000 (see Note 7), (iv) to pay other obligations of $957,000 (see Note 8) and (v) to pay expenses of the Offering. The Company used net proceeds from the exercise of the underwriters’ over-allotment option to redeem common units from certain investors existing prior to the Offering. After this redemption of common units, pre-Offering investors owned 1,288,252 common units and 3,519,126 subordinated units and the public owned 5,750,000 common units (see Note 10).

Concurrent with the closing of the Offering, CHC entered into a new $12 million secured revolving credit facility. At the closing, CHC borrowed $9,000,000 under this facility to retire the remaining balance outstanding under the Tejas Credit Agreement (see Note 7). Additionally, concurrent with the closing of the Offering, CPG amended its existing $100 million secured revolving credit facility (see Note 7).

Note 2—Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the assets, liabilities and results of operations of CE and its subsidiaries for each of the periods presented. As discussed in Note 4, the assets of CFS/LO were acquired in May 2002 and the assets of CFS/Karnes were acquired in September and December 2004. Although the Company owns, through CWDPL, a 62.5% equity investment in Webb/Duval Gatherers (“WDG”), a Texas general partnership, the Company accounts for the investment using the equity method of accounting because the minority general partners have substantive participating rights with respect to the management of WDG (see Note 5). All significant intercompany accounts and transactions are eliminated in the consolidated financial statements.

Copano General Partners, Inc. (“CGP”), a wholly owned indirect subsidiary of CE, is the only entity within the consolidated group subject to federal income taxes. CGP’s operations include (i) its ownership of CWDPL through February 12, 2004 and (ii) its indirect ownership of the managing general partner interest in certain of the Copano Pipelines entities. As of December 31, 2004, CGP had a net operating loss carryforward of approximately $265,000, for which a valuation allowance has been recorded. No income tax expense was recognized for the years ended December 31, 2004, 2003 and 2002. Except for income allocated to CGP, income is taxable directly to the members holding the membership interests in CE.

The number of common units outstanding and per common unit amounts have been restated for all periods presented to reflect the conversion or exchange of pre-Offering common units into post-Offering common units immediately prior to the completion of the Offering (see Note 10).

F-9

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Use of Estimates

The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to 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 management believes the estimates are appropriate, actual results can differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include certificates of deposit with maturities of three months or less at the time of purchase.

Escrow Cash

Escrow cash includes cash that was contractually restricted for interest expense due currently. Restricted cash and cash equivalents are classified as a current or non-current asset based on their designated purpose. Current amounts represent an escrow for the CHC Credit Facility discussed in Note 7.

Concentration and Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable.

The Company places its cash and cash equivalents with high-quality institutions and in money market funds. The Company derives its revenue from customers primarily in the natural gas and utility industries. These industry concentrations have the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers could be affected by similar changes in economic, industry or other conditions. However, the Company believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Company’s customer base. The Company’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

Allowance for Doubtful Accounts

The Company extends 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, the Company makes judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. The Company has established various procedures to manage its credit exposure, including initial credit approvals, credit limits and rights of offset. The Company also uses prepayments and guarantees to limit credit risk to ensure that management’s established credit criteria are met. The activity in the allowance for doubtful accounts is as follows (in thousands):

	Balance at Beginning of Period			Charged to Expense			Write-Offs, net of Recoveries				Balance at End of Period
Year ended December 31, 2004		$	200		$	202		$	(46	)		$	356
Year ended December 31, 2003		$	—		$	208		$	(8	)		$	200
Year ended December 31, 2002		$	—		$	—		$	—			$	—

F-10

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Property, Plant and Equipment

Property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, gas processing, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. The Company charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Company calculates depreciation on the straight-line method principally over 20-year and 30-year estimated useful lives of the Company’s assets. The weighted average useful lives are as follows:

Pipelines and equipment		22 years
Gas processing plant and equipment		29 years
Office furniture and equipment		5 years

The Company capitalizes 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.

The Company reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the asset and its eventual disposition are less than the asset’s carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.

Intangible Assets

Intangible assets consist of rights-of-way, easements and an acquired customer relationship, which the Company amortizes over the term of the agreement or estimated useful life. For the years ended December 31, 2004 and 2003, the weighted average amortization period for the Company’s intangible assets was 10.1 years and 9.3 years, respectively. Amortization expense was $434,000, $377,000 and $358,000 for the years ended December 31, 2004, 2003 and 2002, respectively. Estimated aggregate amortization expense for each of the five succeeding fiscal years and thereafter is approximately: 2005—$420,000; 2006—$407,000; 2007—$368,000; 2008—$300,000; 2009—$232,000; and thereafter—$2,742,000. Intangible assets consisted of the following (in thousands):

	December 31,
	2004			2003
Rights-of-way and easements, at cost	$	6,552		$	6,047
Customer relationship	725			725
Less accumulated amortization	(2,808		)	(2,375		)
Intangible assets, net	$	4,469		$	4,397

Other Assets

Other assets primarily consist of costs associated with debt issuance and long-term contracts and are carried on the balance sheet, net of related accumulated amortization. Amortization of other assets is

F-11

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

calculated using the straight-line method over the maturity of the associated debt or the expiration of the contract.

Transportation and Exchange Imbalances

In the course of transporting natural gas and natural gas liquids for others, the Company may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cashout provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2004 and 2003, the Company had imbalance receivables totaling $454,000 and $380,000 and imbalance payables totaling $602,000 and $554,000, 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 either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Asset Retirement Obligation

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which the obligation is incurred and can be reasonably estimated. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset is recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard became effective for the Company on January 1, 2003.

Under the implementation guidelines of SFAS No. 143, the Company has reviewed its long-lived assets for asset retirement obligation (“ARO”) liabilities and identified any such liabilities. These liabilities include ARO liabilities related to (i) rights-of-way and easements over property not owned by the Company, (ii) leases of certain currently operated facilities and (iii) regulatory requirements triggered by the abandonment or retirement of certain of these assets.

As a result of the Company’s analysis of AROs, the Company determined it was not required to recognize any such potential liabilities. The Company’s rights under its easements are renewable or perpetual and retirement action, if any, is required only upon nonrenewal or abandonment of the easements. The Company currently expects to continue to use or renew all such easement agreements and to use these properties for the foreseeable future. Similarly, under certain leases of currently operated facilities, retirement action is only required upon termination of these leases and the Company does not expect termination in the foreseeable future. Accordingly, management is unable to reasonably estimate and record liabilities for its obligations that fall under the provisions of SFAS No. 143 because it does not believe that any of the applicable assets will be retired or abandoned in the foreseeable future. The Company will record AROs in the period in which the obligation may be reasonably estimated.

F-12

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Revenue Recognition

The Company’s natural gas and natural gas liquids revenue is recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing.

A significant portion of the Company’s sale and purchase arrangements are 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 at the same or at another specified date. These arrangements are 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. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

The Company occasionally enters into buy/sell arrangements that are accounted for on a net basis in the statements of operations as either a natural gas sale or a cost of natural gas, as appropriate.

Transportation, compression and processing-related revenue are recognized in the period when the service is provided and include the Company’s fee-based service revenue for services such as transportation, compression and processing including processing under tolling arrangements.

Derivatives

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Company’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term; however, the Company does have certain contracts which extend through the life of the dedicated production.

Net Loss Per Unit

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

F-13

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Basic and diluted net loss per equivalent unit is calculated as follows (in thousands, except per unit amounts). For periods prior to the Offering, equivalent units were calculated using the weighted average of pre-Offering common units and common special units adjusted by a conversion or exchange factor to reflect the exchange of pre-Offering common units for post-Offering common units immediately prior to completion of the Offering (see Note 10).

	Year Ended December 31,
	2004			2003			2002
Net loss	$	(915	)	$	(4,717	)	$	(1,641	)
Accretion of preferred units	—			(743		)	(1,379		)
Cash distributions to preferred unitholders	—			(810		)	(2,194		)
Paid-in kind distributions to preferred unitholders	—			(2,453		)	(3,853		)
Net loss available—basic and diluted	$	(915	)	$	(8,723	)	$	(9,067	)
Basic weighted average equivalent units	2,599			1,405			1,339
Dilutive weighted average equivalent units	2,604			1,405			1,339
Basic and diluted* net loss per equivalent unit	$	(0.35	)	$	(6.21	)	$	(6.77	)

* The potentially dilutive warrants that were previously held by preferred unitholders and outstanding employee unit options were excluded from the dilutive loss per equivalent unit calculation because to include these equity securities would have been anti-dilutive since the Company reported losses for the periods presented.

CE had 200,000 potentially dilutive employee unit options outstanding as of December 31, 2004 and 3,750,000 potentially dilutive warrants outstanding during the years ended December 31, 2003 and 2002. These potentially dilutive option units and warrants were excluded from the dilutive loss per equivalent unit calculation because to include these options and warrants would have been anti-dilutive since the Company reported losses for the years ended December 31, 2004, 2003 and 2002.

Net loss per unit for the years ended December 31, 2003 and 2002 has not been presented for junior units and junior special units as such units were not entitled to share in earnings for the periods presented.

Accounting for Stock-Based Compensation

The Company uses the intrinsic value method established by Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees” to value unit options issued to employees under the Company’s long-term incentive plan adopted on November 15, 2004. In accordance with APB No. 25 for fixed unit options, compensation is recorded to the extent the fair value of the unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. For the year ended December 31, 2004, the cost of this stock-based compensation program had no impact on the Company’s net loss, as all options granted had an exercise price equal to the market value of the underlying common unit on the date of grant.

F-14

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

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

	Year Ended December 31,
	2004			2003			2002
Net loss, as reported	$	(915	)	$	(4,717	)	$	(1,641	)
Less: Stock-based employee compensation expense determined under fair value method	17			—			—
Pro forma net loss	$	(932	)	$	(4,717	)	$	(1,641	)
Loss per equivalent unit:
Basic—as reported	$	(0.35	)	$	(6.21	)	$	(6.77	)
Basic—pro forma	$	(0.36	)	$	(6.21	)	$	(6.77	)
Diluted—as reported	$	(0.35	)	$	(6.21	)	$	(6.77	)
Diluted—pro forma	$	(0.36	)	$	(6.21	)	$	(6.77	)

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

The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions for 2004 (no options were granted in 2003 and 2002): exercise price of $20.00, expected volatility rate of 17.86%, risk-free interest rate of 3.12% and expected life of 7 years. The Black-Scholes average fair value of options granted in 2004 was $1.44 per unit.

Note 3—New Accounting Pronouncements

Business Combinations and Goodwill

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” Pursuant to SFAS No. 141, all business combinations initiated after June 30, 2001, are to be accounted for using the purchase method of accounting and, therefore, the net assets of an acquired business are to be recorded at fair value. SFAS No. 142 requires that goodwill no longer be subject to amortization over its useful life but, rather, be subject to at least an annual assessment for impairment by applying the fair value-based test. Further, SFAS No. 142 requires other acquired intangible assets be reported separately from goodwill if the benefit of the intangible asset can be sold or transferred or if it is obtained through contractual or other legal rights. In accordance with SFAS No. 142, which became effective for the Company on January 1, 2002, the Company tests other intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. Upon adoption of SFAS No. 142, the Company re-evaluated the life of its customer relationship.

F-15

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3—New Accounting Pronouncements (Continued)

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify such a financial instrument as a liability (or asset in some circumstances). The Company adopted SFAS No. 150 effective July 1, 2003. Upon adoption, the Company began classifying its redeemable preferred units as a liability and began recording the value of the paid-in-kind (“PIK”) preferred unit distributions issued to the redeemable preferred unitholders as interest expense, whereas prior to the adoption of SFAS No. 150, these distributions were recorded as a direct increase to the accumulated deficit.

Share Based Payment

In December 2004, the FASB issued SFAS No. 123 (revised 2004), or SFAS No. 123(R), “Share Based Payment” which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods or services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change to prior guidance for share-based payments for transactions with non-employees. SFAS No. 123(R) eliminates the intrinsic value measurement objective in APB No. 25 and generally requires the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant.

The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). The standard also requires the Company to estimate the number of instruments that will ultimately be issued, rather than accounting for forfeitures as they occur. The Company is required to apply SFAS No. 123(R) to all awards granted, modified or settled in the first reporting period after June 15, 2005. The Company is also required to use either the “modified prospective method” or the “modified retrospective method.” Under the modified prospective method, the Company must recognize compensation cost for all awards granted after the Company adopts the standard and for the unvested portion of previously granted awards that are outstanding on that date. Under the modified retrospective method, the Company must restate previously issued financial statements to recognize the amounts the Company previously calculated and reported on a pro forma basis, as if the prior standard had been adopted. Under both methods, the Company is permitted to use either a straight line or an accelerated method to amortize the cost as an expense for awards with graded vesting. The standard permits and encourages early adoption.

The Company has commenced the analysis of the impact of SFAS 123(R), but has not yet decided: (1) whether the Company will elect early adoption, (2) if the Company elects early adoption, at what date the Company would do so, (3) whether the Company will use the modified prospective method or elect to use the modified retrospective method, and (4) whether the Company will elect to use straight line amortization or an accelerated method. Additionally, the Company cannot predict with reasonable certainty the number of options that will be unvested and outstanding upon adoption. Accordingly, the Company cannot currently quantify with precision the effect that this standard would have on the financial

F-16

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3—New Accounting Pronouncements (Continued)

position or results of operations in the future, except that the Company probably will recognize a greater expense for any awards that the Company may grant in the future than the Company would using the current guidance. If the Company were to adopt SFAS No. 123(R) using the modified retrospective method, our net loss would have been approximately $17,000 more than reported in the year ended December 31, 2004.

Exchanges of Nonmonetary Assets an amendment of APB No. 29.

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

Note 4—Acquisitions

CFS/Karnes

In August 2004, CFS/Karnes acquired a gathering system located in northern Bee and southern Karnes Counties, Texas, for approximately $305,000, which includes $200,000 cash to the seller and $105,000 related to legal and due diligence costs.

In December 2004, CFS/Karnes acquired the Runge gathering system located in Bee, Goliad, Karnes and DeWitt Counties, Texas from Kinder Morgan Tejas Pipeline, L.P. (“KMTP”). This acquisition was accomplished at no cost to CFS/Karnes (other than $32,000 of legal and due diligence transaction costs) by dedicating the natural gas supplies connected and flowing into the Runge gathering system prior to October 1, 2004 to KMTP for purchase under a long term agreement at a purchase price favorable to KMTP. CFS/Karnes assigned a value of $509,000 to the system and the long term supply agreement based on the present value of future cash flows of the existing contracts discounted at 12%. This amount was set up as deferred revenue which is included in other noncurrent liabilities on the consolidated balance sheets and is being amortized on a straight-line basis to natural gas sales over 20 years.

Management allocated the CFS/Karnes purchase price of these asset acquisitions entirely to property, plant and equipment. No pro forma financial information is included as to do so would not be meaningful.

CFS/LO

In May 2002, CFS/LO acquired non-utility gathering assets and contracts from KMTP in Live Oak, Atascosa and Duval Counties, Texas for a cash payment of $3,000,000. The consolidated financial statements include the results of operations of CFS/LO for the period subsequent to the acquisition. Management allocated the purchase price of this asset acquisition entirely to property, plant and equipment.

F-17

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Investment in Unconsolidated Affiliate

In November 2001, the Company acquired CWDPL, which owned a 15% general partnership interest in WDG, for $1,300,000 in cash. From November 27, 2001 through January 31, 2002, CWDPL accounted for its investment in WDG using the cost method of accounting.

On February 1, 2002, the Company, through CWDPL, completed the acquisition of an additional 47.5% general partnership interest in WDG for $3,858,000, comprised of $3,750,000 cash paid to the seller and $108,000 in legal and other direct acquisition costs. As a result of this transaction, CWDPL now holds a 62.5% general partnership interest in WDG and became the operator of WDG’s natural gas gathering systems located in Webb and Duval Counties, Texas. Although CWDPL owns a majority interest in WDG and operates WDG, the Company uses the equity method of accounting for its investment in WDG because the terms of the general partnership agreement of WDG provide the minority general partners substantive participating rights with respect to the management of WDG. The investment in WDG, an unconsolidated affiliate, totaled $4,371,000 and $4,072,000 as of December 31, 2004 and 2003, respectively. As of December 31, 2004 and 2003, the investment in WDG was carried at $250,000 and $270,000, respectively, less than the amount of the underlying equity in net assets (5% and 6%, respectively, of total investment of unconsolidated affiliate). This difference is being amortized into income on a straight-line basis over the life of the underlying related property and equipment of WDG. Equity in earnings (loss) from unconsolidated affiliate is included in income from operations as the operations of WDG are integral to the Company.

F-18

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Investment in Unconsolidated Affiliate (Continued)

The summarized financial information for investment in unconsolidated affiliate, which is accounted for using the equity method, is as follows (in thousands):

Webb/Duval Gatherers

Summary Historical Financial Information

									Period from
									February 1,
									2002 through
	Year Ended December 31,								December 31,
	2004				2003				2002
Operating revenue		$	4,605			$	3,180			$	2,436
Operating expenses		(3,504		)		(3,017		)		(3,051		)
Depreciation		(655		)		(591		)		(526		)
Net income (loss)		446				(428		)		(1,141		)
Ownership %		62.5		%		62.5		%		62.5		%
		278				(268		)		(713		)
CWDPL share of management fee charged to WDG		120				120				110
Amortization of difference between the carried investment and the underlying equity in net assets		21				21				19
Equity in earnings (loss) from unconsolidated affiliate		$	419			$	(127	)		$	(584	)
Distributions from unconsolidated affiliate		$	—			$	—			$	145
Current assets		$	2,348			$	3,075
Noncurrent assets		8,283				8,526
Current liabilities		(3,237		)		(4,653		)
Net assets		$	7,394			$	6,948

Note 6—Property, Plant and Equipment

Property, plant and equipment consisted of the following (in thousands):

	December 31,
	2004			2003
Property, plant and equipment, at cost
Pipelines and equipment	$	93,393		$	86,244
Gas processing plant and equipment	48,711			47,948
Construction in progress	1,349			600
Office furniture and equipment	1,933			1,420
	145,386			136,212
Less accumulated depreciation and amortization	(25,703		)	(19,180		)
Property, plant and equipment, net	$	119,683		$	117,032

F-19

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt

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

	December 31,
	2004		2003
Current portion of long-term debt:
CHC Credit Agreement	$	—	$	7,800
Long-term debt:
CPG Credit Agreement	$	48,000	$	27,500
CHC Facility	9,000		—
Total	$	57,000	$	27,500
Subordinated Debt:
Tejas Credit Agreement	$	—	$	30,398

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

CPG Credit Agreement

On November 27, 2001, CPG and certain Copano Pipelines operating subsidiaries entered into a $20,000,000 revolving credit agreement (the “CPG Credit Agreement”) with a syndicate of commercial banks, including Fleet National Bank (“Fleet”), a subsidiary of Bank of America, as the administrative agent. In August 2003, the CPG Credit Agreement was amended to increase the commitment amount from $20,000,000 to $27,500,000. In February and March 2004, CPG and the additional borrowers amended and restated the CPG Credit Agreement to, among other things, increase the lenders’ commitment amount to $100 million and extend maturity of the facility to February 12, 2008. In connection with the February 2004 amendment, CFS/CGC became an additional obligor under the CPG Credit Agreement when CFS/CGC was conveyed to CPG, and CWDPL ceased to be an obligor under the credit facility when it was conveyed to CE. In connection with the closing of the Offering, on November 15, 2004, the CPG Credit Agreement was amended to, among other things, modify certain financial covenants to permit CPG to make cash distributions to CE to the extent of “available cash” (as defined in the CPG Credit Agreement). Additional borrowings under the CPG Agreement in February 2004 were used primarily by CPG to acquire CFS/CGC from CHC, which in turn used the proceeds to pay in full $7,800,000 outstanding under the CHC Credit Agreement discussed below and to reduce the outstanding balance under the Tejas Credit Agreement, discussed below, by $15,199,000. The balance outstanding under the CPG Credit Agreement totaled $48,000,000 and $27,500,000 as of December 31, 2004 and 2003, respectively. Amounts advanced under the CPG Credit Agreement have been used to retire existing debt, to finance capital expenditures, including construction projects, acquisitions of pipelines and investments in unconsolidated affiliate, and to meet working capital requirements. Future borrowings under this facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The CPG credit facility is available to be drawn on and repaid without restriction so long as CPG is in compliance with the terms of the CPG Credit Agreement, including certain financial covenants.

F-20

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt (Continued)

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

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

· EBITDA (as defined) to interest expense of not less than 3.5 to 1.0;

· total debt to EBITDA of not more than 4.5 to 1.0;

· total senior debt to EBITDA of not more than 3.75 to 1.0;

· minimum tangible net worth; and

· positive net working capital (excluding current debt maturities)

Based upon the senior debt to EBITDA ratio calculated as of December 31, 2004 (utilizing trailing four quarters’ EBITDA), CPG had approximately $24,865,000 of unused capacity under the CPG Credit Agreement.

Management believes that CPG and its subsidiaries are in compliance with the financial covenants under the CPG Credit Agreement as of December 31, 2004. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies.

At CPG’s election, interest under this credit facility is determined by reference to (1) the reserve-adjusted London interbank offered rate, or LIBOR, plus an applicable margin between 1.75% and 3% per annum or (2) the prime rate plus, in certain circumstances, an applicable margin between 0.25% and 1.5% per annum. The interest is payable quarterly for prime interest 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. During 2004, 2003 and 2002, the effective average interest rate on borrowings under the CPG Credit Agreement was 4.01%, 3.72% and 4.97%, respectively. A quarterly commitment fee of between 0.375% and 0.5% per annum is charged on the unused portion of the credit facility and was 0.5% at December 31, 2004 and 2003.

Interest and other financing costs related to the CPG Credit Agreement totaled $2,971,000, $1,181,000 and $1,043,000 for the years ended December 31, 2004, 2003 and 2002, respectively. CPG additionally incurred other costs in connection with this credit facility, including reimbursement of fees

F-21

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt (Continued)

paid by Fleet for legal and other professional services in connection with the establishment of the facility and subsequent amendments. These costs are being amortized over the remaining term of the CPG Credit Agreement, and as of December 31, 2004 and 2003, the unamortized portion of debt issue costs totaled $1,736,000 and $330,000, respectively.

CHC Credit Agreement

In November 2001, CHC and its then subsidiaries entered into a $35 million credit agreement (the “CHC Credit Agreement”) with a syndicate of commercial banks. In February 2004, this credit facility was paid in full and terminated using proceeds from the conveyance of a CFS/CGC to CPG discussed above. Amounts advanced under the CHC Credit Agreement were used to finance debt issue costs and capital expenditures, including construction projects and the acquisition of the CHC assets, and to meet working capital requirements.

Interest and other financing costs related to the CHC Credit Agreement totaled $446,000, $1,488,000 and $2,031,000 for the years ended December 31, 2004, 2003 and 2002, respectively. CHC additionally incurred other costs in connection with this credit facility, including reimbursement of fees paid by Fleet for legal and other professional services in connection with establishment of the facility and subsequent amendments. These costs were being amortized over the remaining term of the CHC Credit Agreement, and as of December 31, 2003, the unamortized portion of debt issue costs totaled $396,000. In February 2004, effective with the early termination of this agreement, the Company charged $314,000 to interest expense, representing the balance of the unamortized debt issue costs.

CHC Facility

Concurrent with the closing of the Offering, on November 15, 2004, CHC and certain of its subsidiaries entered into a $12 million secured revolving credit facility (the “CHC Facility”) with Comerica Bank due January 31, 2007. At the closing, CHC borrowed $9,000,000 under this facility to retire the remaining balance outstanding under the Tejas Credit Agreement discussed below. CHC expects to use the remaining amount of this credit facility to finance capital expenditures (including construction and expansion projects) as well as meet working capital requirements of its processing operations.

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

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

· EBITDA (as defined) to interest expense of not less than 3.25 to 1.0;

F-22

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt (Continued)

· total senior debt to EBITDA of not more than 3.5 to 1.0 at closing, reducing to not more than 2.75 to 1.0 over the two-year term of the loan;

· positive net working capital (excluding current debt maturities);

· minimum tangible net worth;

· make maintenance capital expenditures of not more than $2.5 million per calendar year; and

· maintain an interest reserve account of at least $1.0 million.

At CHC’s election, interest under this revolving credit facility is determined by reference to (1) the reserve-adjusted interbank offered rate, or IBOR, plus an applicable margin between 2.5% and 3.5% per annum or (2) the prime rate plus, in certain circumstances, an applicable margin of up to 1.5% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for IBOR loans, except that if the interest period for an IBOR loan is six months, interest will be paid at the end of each three-month period. During 2004, the effective average interest rate on borrowings under the CHC Facility was 4.77%. A quarterly commitment fee of between 0.3% and 0.5% per annum is charged on the unused portion of the credit facility and was 0.3% at December 31, 2004.

Interest and other financing costs related to the CHC Facility totaled $69,000 for the year ended December 31, 2004. CHC additionally incurred other costs in connection with this credit facility, including reimbursement of fees paid by Comerica Bank for legal and other professional services in connection with establishment of the facility. These costs were being amortized over the term of the CHC Facility, and as of December 31, 2004, the unamortized portion of debt issue costs totaled $188,000.

Management believes that CHC and its subsidiaries are in compliance with the covenants under the CHC Facility as of December 31, 2004. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies.

Tejas Credit Agreement

In 2001, CHC and its then subsidiaries and Tejas Energy NS, LLC (“Tejas”) entered into a subordinated credit agreement (the “Tejas Credit Agreement”) which provided for a $21.2 million original subordinated term loan. CHC and its then subsidiaries used the amounts borrowed under the Tejas Credit Agreement in partial payment of the acquisition price for certain assets acquired from Tejas on August 14, 2001, including the Company’s gas processing plant. In connection with the Tejas Credit Agreement, CHC issued a warrant to Tejas (the “Tejas Warrant”), which provided Tejas the right to acquire up to 10% of the membership interests (100,000 equity membership interests) of CHC.

In 2003, the CHC Borrowers issued an additional $850,000 subordinated note under the Tejas Credit Agreement to Tejas in exchange for certain modifications to the agreement and final settlement of purchase price adjustments related to the acquisition of the assets from Tejas. In February 2004 and upon termination of the CHC Credit Agreement discussed above, the CHC borrowers and Tejas further amended and restated the Tejas Credit Agreement to provide for (i) the prepayment without penalty of $15,199,000 of principal and interest outstanding under the agreement, (ii) the release of CFS/CGC as a borrower under the agreement and (iii) the grant to Tejas of a first priority security interest in the assets of CHC and the remaining borrowers, with the exception of certain working capital interests. In connection with the amended credit facility, the exercise price of the Tejas Warrant was repriced at $41.24 per

F-23

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Long-Term Debt (Continued)

membership interest, or $4,124,000 in the aggregate. As a result of this repricing, CHC assigned an allocated value of $395,000 to the warrant based on the repurchase price of the warrant, which was $405,000. The allocated warrant value amount was recorded as a discount against the remaining balance of the amount outstanding under the Tejas Credit Agreement and as an other noncurrent liability.

The balance of the amount outstanding under the Tejas Credit Agreement of $16,013,000 was repaid in full on November 15, 2004, concurrent with the completion of the Offering and the closing of the CHC Facility discussed above. CHC used $9,000,000 borrowed under the CHC Facility and $7,000,000 of Offering proceeds to retire the debt outstanding under the Tejas Agreement. CHC used cash on hand to repurchase the Tejas Warrant for $405,000. As a result of repurchasing the Tejas Warrant, the Company recorded additional interest expense of $330,000 in November 2004, which represented the write off of the remaining discount associated with the Tejas Warrant as such redemption is considered an early extinguishment of debt.

Borrowings under the Tejas Credit Agreement bore interest at 14% per annum, payable quarterly. Pursuant to the modified terms of the agreement, interest accrued through March 31, 2004 was paid by the issuance of payment-in-kind notes, or PIK notes. After March 31, 2004, CHC made all interest payments in cash. Interest expense totaled $2,214,000, $3,908,000 and $3,286,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

Scheduled Maturities of Long-term Debt

Scheduled maturities of long-term debt as of December 31, 2004 were as follows (in thousands):

Year	Principal Amount
2005	$	—
2006	—
2007	9,000
2008	48,000
	$	57,000

Note 8—Other Long-Term Liabilities

During May 1996, Agua Dulce purchased gathering pipelines and related assets for $6,000,000 in total consideration, of which $4,800,000 was paid in cash and $1,200,000 payable without interest, based upon volumes of gas transported through the system. As of December 31, 2003, the balance of Agua Dulce’s obligation totaled $991,000. The balance, if any, was payable in 2006, or sooner, upon sale of the system or the date on which Agua Dulce and its affiliates participate as issuers of equity securities in a registered public offering. The Company used $957,000 of Offering proceeds to pay the outstanding balance under this arrangement in November 2004.

Note 9—Redeemable Preferred Units

Through a series of transactions occurring between August 2001 and November 2001, CE issued redeemable preferred units in consideration for $60,000,000 in cash. The cash proceeds from these issuances were used primarily to fund the asset acquisition from Tejas, the acquisition of the minority

F-24

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9—Redeemable Preferred Units (Continued)

interests in certain predecessor entities and construction costs related to the Hebbronville pipeline assets. For the first four years following the initial issuance of the preferred units, CE had the right to pay the quarterly distributions in preferred units at a 10% rate. Except for cash distributions of $810,000 and $2,194,000 during the years ended December 31, 2003 and 2002, respectively, the board elected to pay the preferred distributions in preferred units for all required quarterly distributions, thereby increasing the number of preferred units and aggregated amount outstanding. As of December 31, 2003, preferred units issued and outstanding totaled 703,870 with an aggregate face value of $70,387,000.

Additionally, the preferred unitholders were issued warrants to purchase up to 3,750,000 common units of CE exercisable at a price of $16 per unit until August 14, 2011. Proceeds from the issuance of the preferred units were allocated between the warrants and the preferred units based on their respective fair values. The fair value of each warrant as of the date of grant was $4.34 using the Black-Scholes option pricing model and the following assumptions: exercise price of $16.00, expected volatility rate of 19%, risk-free interest rate of 4.97% and expected life of 10 years. The Company used the Black-Scholes warrant value to assign an allocated value of $12,799,000, or $3.41 per warrant, and $47,201,000 to the preferred units. The allocated warrant value amount was recorded as a discount against the redeemable preferred units and as an increase to paid-in capital. This discount was accreted as additional distributions (interest expense after the adoption of SFAS No. 150, see Note 3) through the mandatory redemption date. As of December 31, 2003, the remaining balance of the discount amount totaled $9,405,000.

Prior to the closing of the Offering in November 2004, the preferred unitholders exchanged these warrants for 1,211,120 common units and 2,091,048 subordinated units (as described in Note 10) of CE based upon the exercise price of the warrants and the value of the underlying common units issued to the public. In addition, net proceeds from the Offering were used to redeem all outstanding redeemable preferred units for $78,077,000. As a result of this redemption, the Company recorded additional interest expense of $7,946,000 in November 2004, which represented the write off of the remaining discount associated with the redeemable preferred units as such redemption is considered an early extinguishment of debt.

Additionally, CE had incurred costs in connection with the issuance of the preferred units and warrants, including fees paid to the preferred unit purchasers, as well as legal and other professional fees. These costs, totaling $1,704,000, were recorded as a reduction to paid-in capital. Upon adoption of SFAS No. 150, $1,258,000, representing the amount of unamortized costs as of July 1, 2003 had these costs been treated as debt issue costs from the time of issuance, was reclassified from paid-in capital to debt issue costs and was being amortized over the remaining outstanding period of the redeemable preferred units. The unamortized portion of these debt issue costs totaled $1,135,000 as of December 31, 2003. As a result of the redemption of the preferred units using proceeds from the Offering, CE wrote off the unamortized balance of issuance costs associated with the redeemable preferred units of $921,000.

Note 10—Members’ Capital

Common Units and Subordinated Units After the Offering

On November 15, 2004, immediately prior to the completion of the Offering, (i) Copano Partners L.P. (“Copano Partners”), an entity controlled by Mr. John R. Eckel, Jr., Chairman of the Board of Directors

F-25

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Members’ Capital (Continued)

and Chief Executive Officer of the Company, exchanged its common units and junior units for 763,221 common units and 1,317,733 subordinated units representing approximately 19.71% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters’ over-allotment option and (ii) two executive officers exchanged their common special units and junior special units for an aggregate of 63,911 common units and 110,345 subordinated units representing approximately 1.65% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters’ over-allotment option. Additionally as discussed in Note 9, on November 15, 2004, immediately prior to the completion of the Offering, the preferred unitholders exchanged their warrants for an aggregate of 1,211,120 common units and 2,091,048 subordinated units. After redemption of certain common units received by the former preferred unitholders using proceeds from the underwriters’ exercise of the over-allotment option, the former preferred unitholders held an aggregate of 461,120 common units and 2,091,048 subordinated units representing approximately 24.17% of the outstanding units of CE upon completion of the Offering including the exercise of the underwriters’ over-allotment option.

On November 15, 2004, CE completed the Offering by issuing 5,750,000 common units at $20.00 per common unit representing 54.46% of the outstanding units of CE. Expenses of the Offering (including underwriting discounts and commissions of $8,050,000) totaled $13,170,000. After the redemption of certain common units using net proceeds from the underwriters’ over-allotment option and as of December 31, 2004, pre-Offering investors owned an aggregate of 1,288,252 common units and the public owned an aggregate of 5,750,000 common units.

Subordinated units represent limited liability interests in CE, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. All 3,519,126 subordinated units outstanding after the Offering and as of December 31, 2004 were held by pre-Offering investors and represented approximately 33% of total units outstanding after the Offering. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.40 per unit for each quarter since the commencement of operations. Subordinated units will convert into common units on an one-for-one basis when the subordination period ends. Pursuant to CE’s limited liability company agreement, the subordination period will extend until the first day of any quarter beginning after December 31, 2006 that each of the following financial tests is met: (1) distributions of “available cash from operating surplus” (as defined) on each of the outstanding common units and subordinated units for the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the minimum quarterly distribution; (2) the “adjusted operating surplus” (as defined) generated during the two consecutive four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all outstanding common units and subordinated units; and (3) there are no arrearages in payment of the minimum quarterly distributions on the common units.

Common Units and Junior Units Prior to the Offering

In transactions occurring on August 14, 2001 and November 27, 2001, CE issued 1,299,020 (as restated for the conversion related to the Offering) common units and 620,000 junior units to Copano Partners in exchange for general and limited partnership interests in certain operating entities of CE. Prior to the completion of the Company’s Offering, a common unitholder could not receive any distributions until the preferred unitholders had been redeemed in full, other than distributions for any fiscal year, in amounts

F-26

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Members’ Capital (Continued)

equal to net taxable income of such unitholder as reflected on its Schedule K-1 multiplied by the maximum federal income tax rate then in effect. Junior unitholders were entitled to share in distributions only after preferred units had been redeemed in full and after common unitholders had received a distribution of $20 per common unit.

Common Special Units and Junior Special Units Prior to the Offering

Effective January 2002, 212,000 nonvoting special units of CE were designated, 154,000 of which were designated as common special units and 58,000 of which were designated as junior special units. Of the designated amounts, 54,000 common special units and 18,000 junior special units were sold, effective January 2002, to an executive officer of the Company and, effective April 1, 2003, an additional 100,000 common special units and 40,000 junior special units were sold to another executive officer of the Company. The acquisition price for the common special units and the junior special units was $1.00 per unit and $0.50 per unit, respectively. The initial purchase of the 72,000 special units issued effective January 2002 to an executive officer was financed by a subscription receivable. The second purchase of the 140,000 special units issued effective April 1, 2003 to another executive officer was financed by a subscription receivable, one third, or $40,000, of which was forgiven on April 1, 2004.

On July 30, 2004, Copano/Operations, Inc. (“Copano Operations”), an entity controlled by Mr. Eckel and which provides management, operations and administrative support services to the Company, loaned these two executive officers a total of $143,000. These officers used the loan proceeds to pay CE for the balance of the acquisition price for the special units (subscription receivable). See Distributions below.

With respect to distributions, common special unitholders and junior special unitholders had the same rights as common unitholders and junior unitholders, respectively; provided, however, that upon certain liquidating events of the Company, (i) special unitholders had a liquidation preference over all other unitholders with respect to an amount of liquidation proceeds equal to the original acquisition price of the special units and (ii) the amount of the balance that otherwise would be distributed to common special unitholders would be reduced by an amount equal to the number of common special units multiplied by $16.

Distributions

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

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

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

F-27

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Members’ Capital (Continued)

Employee Incentive Plan

In November 2004, CE adopted a long-term incentive plan for its directors, employees and employees of its affiliates who perform services for CE. For purposes of the plan, CE’s affiliates include Copano Operations. The plan consists of four components: restricted units, phantom units, unit options and unit appreciation rights and limits the number of units that may be delivered pursuant to awards to 800,000 units, provided no more than 25% of such units (subject to certain adjustments) may be delivered as payment with respect to restricted units and phantom units. The plan is administered by the compensation committee of CE’s board of directors.

Unit Options

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

On November 15, 2004, CE granted all employees, excluding Mr. Eckel, a total of 200,000 unit options to purchase an equal number of common units at $20.00 per unit. These unit options will vest in five equal annual installments commencing with the first anniversary of the grant date or will become exercisable upon a change of control, death or disability. Outstanding options have remaining contractual lives of approximately 10 years at December 31, 2004.

A summary of the unit option activity for the year ended December 31, 2004 is provided below:

	December 31, 2004
	Number of units	Weighted average exercise price
Outstanding, beginning of period	—		—
Granted	200,000		$	20.00
Exercised	—		—
Forfeited	—		—
Outstanding, end of period	200,000		$	20.00
Options exercisable at end of period	—		—
Weighted average fair value of options granted			$	1.44

Restricted Units

A restricted unit is a common unit that vests over a period of time and that during such time is subject to forfeiture. In addition, restricted units will vest upon a change in control of CE, unless provided otherwise by the compensation committee. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted units.

The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore,

F-28

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Member’s Capital (Continued)

plan participants will not pay any consideration for the common units they receive and CE will receive no remuneration for the units.

On December 13, 2004, CE awarded 3,000 restricted common units to each of its six independent directors, for a total of 18,000 units with an intrinsic value of $434,000. Each restricted unit grant vests in equal one-third annual installments commencing on the first anniversary of the grant date or upon a change of control, death, disability or, in certain circumstances, retirement and the intrinsic value of the units is amortized into general and administrative expense over the vesting period. The Company recognized expense of $13,000 related to the amortization of these restricted units in 2004.

Note 11—Related Party Transactions

Operations Services

Through December 31, 2004, the Company did not directly employ any persons to manage or operate its business other than certain Delaware-based officers. With respect to the Texas operating subsidiaries of the Company, Copano Operations provided management, operations and administrative support services for the Company. The Company reimbursed Copano Operations for all direct and indirect costs of these services. Copano Operations charged these subsidiaries, without markup, based upon total monthly expenses incurred by Copano Operations less (i) a fixed allocation to reflect expenses incurred by Copano Operations for the benefit of certain entities controlled by Mr. Eckel and (ii) any costs to be charged directly to an entity for which Copano Operations performed services. Management believes that this methodology was reasonable. For the years ended December 31, 2004, 2003 and 2002, the Company reimbursed Copano Operations $15,355,000, $12,190,000 and $9,329,000, respectively, for administrative and operating costs, including payroll and benefits expense for both field and administrative personnel of the Company. These costs are included in operations and maintenance expenses and general and administrative expenses on the consolidated statements of operations. As of December 31, 2004 and 2003, amounts payable by the Company to Copano Operations were $38,000 and $1,265,000, respectively.

Effective January 1, 2005 and pursuant to a general and administrative services agreement with Copano Operations, Copano Operations transferred responsibility to CPNO Services, L.P., an indirect wholly owned subsidiary of CE, for a significant portion of the services, including its employment of certain employees on the Company’s behalf, that Copano Operations had previously provided to the Company. Under the general and administrative services agreement, the Company continues to reimburse Copano Operations for all direct and indirect costs of the services provided to the Company by Copano Operations using the same methodology as utilized prior to January 1, 2005.

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

Natural Gas Transactions

During the years ended December 31, 2004, 2003 and 2002, the Company purchased natural gas from affiliated companies of Mr. Eckel totaling $1,474,000, $1,896,000 and $1,117,000, respectively, and

F-29

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 11—Related Party Transactions (Continued)

provided gathering and compression services to affiliated entities of Mr. Eckel totaling $75,000, $33,000 and $46,000, respectively. Additionally, affiliated companies of Mr. Eckel reimbursed the Company $53,000, $34,000 and $15,000 for the years ended December 31, 2004, 2003 and 2002, respectively, in gas lift costs which are reflected as a reduction of operations and maintenance expense in the consolidated statements of operations. Management believes these purchases and sales were on terms no less favorable than those that could have been achieved with an unaffiliated entity. As of December 31, 2004 and 2003, amounts payable by the Company to affiliated companies of Mr. Eckel, other than Copano Operations, totaled $89,000 and $106,000, respectively.

The Company paid WDG for transportation and purchased natural gas from WDG. Natural gas purchases and transportation, net of natural gas sales to WDG, totaled $926,000, $665,000 and $1,312,000, for the years ended December 31, 2004, 2003 and 2002, respectively. Additionally, as operator of WDG, CWDPL charges WDG a monthly administrative fee of $16,000 and has made advances to WDG for capital expenditures. As of December 31, 2004 and 2003, the Company’s net receivable from WDG totaled $1,141,000 and $651,000, respectively.

Other

A subsidiary of Merrill Corporation (“Merrill”), an affiliate of Credit Suisse First Boston Private Equity which held an interest in the Company as of December 31, 2004, provided the Company with printing and distribution services in connection with the Offering and continues to provide assistance with printing and on-going public filings. For the year ended December 31, 2004, the Company incurred $564,000 of printing, distribution and filing costs from Merrill, $559,000 of which are recorded as Offering costs. Management believes that the Company obtained these services on terms no less favorable than those that could have been achieved with an unaffiliated entity.

Note 12—Customer Information

The Company had three third-party customers that accounted for 27% (Copano Pipelines/Copano Processing), 22% (Copano Processing) and 14% (Copano Processing) of its consolidated revenue in 2004. The Company had four third-party customers that accounted for 33% (Copano Pipelines/Copano Processing), 14% (Copano Pipelines), 9% (Copano Pipelines/Copano Processing) and 8% (Copano Pipelines) of its consolidated revenue in 2003. The Company had three third-party customers that accounted for 31% (Copano Pipelines/Copano Processing), 16% (Copano Pipelines) and 16% (Copano Processing) of its consolidated revenue in 2002. See Note 17 for additional segment information.

The Company had two major suppliers in 2004 that accounted for 11% and 8% of its consolidated cost of natural gas sold. The Company had two major suppliers in 2003 that accounted for 8% and 8% of its consolidated cost of natural gas sold. The Company had two major suppliers in 2002 that accounted for 13% and 9% of its consolidated cost of natural gas sold. All of these major suppliers during the three years ended December 31, 2004 sold volumes to the Copano Pipelines segment. See Note 17 for additional segment information.

The Company had three third-party customers that accounted for 31% (Copano Pipelines/Copano Processing), 29% (Copano Processing) and 11% (Copano Pipelines) of its consolidated accounts receivable as of December 31, 2004. The Company had four third-party customers that accounted for 26%

F-30

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 12—Customer Information (Continued)

(Copano Pipelines/Copano Processing), 15% (Copano Pipelines), 13% (Copano Processing) and 12% (Copano Pipelines) of its consolidated accounts receivable as of December 31, 2003. See Note 17 for additional segment information.

Note 13—Risk Management Activities

From time to time, the Company may utilize a hedging strategy to mitigate the risk of the volatility of natural gas prices. For the years ended December 31, 2004, 2003 and 2002, no such hedging positions were purchased or exercised and no option positions were outstanding as of December 31, 2004 or 2003.

The CHC Credit Agreement and CPG Credit Agreement required both CHC and CPG to enter into interest rate risk management activities within 90 days of the establishment of the facilities. In March 2002, CHC and CPG entered into interest rate swap agreements with Fleet under the then existing credit facilities. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:

Effective Date	Expiration Date	Notional Amount		Fixed Rate		Amounts Paid in 2002		Fair Value December 31, 2002				Amounts Paid in 2003
March 1, 2002	March 1, 2003	$	15,000,000	2.57	%	$	80,209		$	(43,391	)	$	43,391
March 1, 2002	September 1, 2003	5,000,000		3.03	%	44,370			(60,832		)	64,014
March 1, 2002	September 1,2003	10,000,000		3.03	%	88,740			(121,665		)	128,028

As of December 31, 2004 and 2003, no such interest rate swap contracts were outstanding.

Note 14—Fair Value of Financial Instruments

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of December 31, 2004 and 2003, the debt associated with the CPG Credit Agreement, the CHC Facility and the CHC Credit Agreement (repaid in February 2004) bore interest at floating rates. As such, carrying amounts of these debt instruments approximate fair values.

The debt associated with the Tejas Credit Agreement (repaid in November 2004) had a fixed rate of 14%. As of December 31, 2003, management believed that the carrying amount of the subordinated debt approximated its fair value.

Note 15—Commitments and Contingencies

Commitments

For the years ended December 31, 2004, 2003 and 2002, rental expense for office space, leased vehicles and leased compressors and related field equipment used in the Company’s operations totaled $1,598,000, $1,631,000 and $1,066,000, respectively. As of December 31, 2004, commitments under the Company’s lease obligations for the next five years and thereafter are payable as follows: 2005—$670,000; 2006—$454,000; 2007—$350,000; 2008—$344,000; 2009—$344,000; and thereafter—$143,000. During 2003, certain CE subsidiaries became co-lessors of office space with Copano Operations.

F-31

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 15—Commitments and Contingencies (Continued)

The Company has both fixed and variable contractual commitments arising in the ordinary course of its natural gas marketing activities. As of December 31, 2004, the Company had fixed contractual commitments to purchase 364,250 million British thermal units (“MMBtu”) of natural gas in January 2005. As of December 31, 2004, the Company had fixed contractual commitments to sell 2,461,400 MMBtu of natural gas in January 2005 and 295,000 MMBtu of natural gas between February 2005 and March 2005. All of these contracts are based on index-related market pricing. Using index-related market prices as of December 31, 2004, total commitments to purchase natural gas related to such agreements equaled $2,086,000 and the total commitment to sell natural gas under such agreements equaled $13,826,000. The Company’s commitments to purchase variable quantities of natural gas at index-based prices range from contract periods extending from one month to the life of the dedicated production. During December 2004, natural gas volumes purchased under such contracts equaled 4,591,203 MMBtu. The Company’s commitments to sell variable quantities of natural gas at index-based prices range from contract periods extending from one month to 2012. During December 2004, natural gas volumes sold under such contracts equaled 565,440 MMBtu.

Guarantees

In November 2002, the FASB issued Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In certain instances, this interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

From July 8, 2002 through April 1, 2004, the Company guaranteed certain vehicle lease obligations of Copano Operations for vehicles operated for the benefit of certain of Copano operating entities. Effective as of April 2, 2004, the vehicle leases were transferred by Copano Operations to Hebbronville and Hebbronville, as lessee, guarantees the lessor a minimum residual sales value upon the expiration of the lease and sale of the underlying vehicle. Certain of the Copano Pipelines entities currently guarantee the lease payment obligations, including the residual sales value. As of December 31, 2004, the Company guaranteed $170,000 related to these lease payment obligations. As of December 31, 2004, aggregate guaranteed residual values for vehicles under these operating leases were as follows (in thousands):

	2005		2006			2007			2008		Thereafter			Total
Lease residual values	$	176		$	36		$	55	$	—		$	—	$	267

Effective April 12, 2003, the Company has guaranteed certain telephone equipment lease obligations (approximately $21,600 of lease payment obligations as of December 31, 2004) of Copano Operations. The use of this telephone equipment by the Company is included in the support services provided by Copano Operations to the Company. See Note 11.

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

FIN 45 also sets forth disclosure requirements for guarantees by a parent company on behalf of its subsidiaries. CE or a subsidiary entity, from time to time, may issue parent guarantees of commitments resulting from the ongoing activities of subsidiary entities. Additionally, a subsidiary entity may from time to time issue a guarantee of commitments resulting from the ongoing activities of another subsidiary entity.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 15—Commitments and Contingencies (Continued)

The guarantees generally arise in connection with a subsidiary commodity purchase obligation, subsidiary lease commitments and subsidiary bank debt. The nature of such guarantees is to guarantee the performance of the subsidiary entities in meeting their respective underlying obligations. Except for operating lease commitments, all such underlying obligations are recorded on the books of the subsidiary entities and are included in the consolidated financial statements as obligations of the combined entities. Accordingly, such obligations are not recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary entity. In satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary entity. As of December 31, 2004, the approximate amount of parental guaranteed obligations were as follows (in thousands):

	2005		2006		2007		2008		Total
Bank debt	$	—	$	—	$	9,000	$	48,000	$	57,000
Commodity purchases	5,400		—		—		—		5,400
	$	5,400	$	—	$	9,000	$	48,000	$	62,400

Regulatory Compliance

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

Litigation

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

Note 16—Supplemental Disclosures to the Statements of Cash Flows

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

	Year Ended December 31,
	2004		2003		2002
Interest	$	3,891	$	1,611	$	2,251
Taxes	—		28		—

F-33

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 16—Supplemental Disclosures to the Statements of Cash Flows (Continued)

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

	Year Ended December 31,
	2004			2003			2002
Issuance of subordinated notes	$	—		$	850		$	—
Decrease in other current liabilities	—			(850		)	—
Increase of redeemable preferred units related to the issuance of PIK units	—			2,453			3,853
Decrease in members’ capital related to the issuance of PIK units	—			(2,453		)	(3,853		)
Increase of redeemable preferred units related to the accretion of warrant value	—			743			1,379
Decrease in members’ capital related to the accretion of warrant value	—			(743		)	(1,379		)
(Decrease) increase other comprehensive income (loss)	—			226			(226		)
Increase (decrease) other current liabilities	—			(226		)	226
Increase in members’ capital	—			1,258			—
Decrease of redeemable preferred units	—			(1,258		)	—
Increase in equity in loss from unconsolidated affiliate	120			120			110
Decrease in accounts receivable from affiliates	(120		)	(120		)	(110		)
Increase in property, plant and equipment	(890		)	—			—
Increase in other noncurrent liabilities	890			—			—

Note 17—Segment Information

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

F-34

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 17—Segment Information (Continued)

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

	Copano Pipelines			Copano Processing			Corporate			Eliminations			Total
*Year Ended December 31, 2004:*
Sales to external customers	$	274,595		$	163,061		$	—		$	—		$	437,656
Intersegment sales	146,812			18,442			—			(165,254		)	—
Interest expense and other financing costs	2,971			3,134			17,643			(588		)	23,160
Depreciation and amortization	4,832			2,390			65			—			7,287
Equity in earnings in consolidated affiliate	(419		)	—			—			—			(419		)
Segment profit (loss)	11,878			7,195			(19,988		)	—			(915		)
Segment assets	150,375			68,966			1,383			(42,325		)	178,399
Capital expenditures	7,989			820			111			—			8,920
*Year Ended December 31, 2003:*
Sales to external customers	$	265,121		$	119,450		$	—		$	—		$	384,571
Intersegment sales	139,824			42,116			—			(181,940		)	—
Interest expense and other financing costs	2,837			3,740			5,531			—			12,108
Depreciation and amortization	4,328			1,755			8			—			6,091
Equity in loss from unconsolidated affiliate	127			—			—			—			127
Segment profit (loss)	10,567			(9,375		)	(5,909		)	—			(4,717		)
Segment assets	148,872			98,511			2,098			(87,772		)	161,709
Capital expenditures	3,727			2,465			—			—			6,192
*Year Ended December 31, 2002:*
Sales to external customers	$	111,400		$	113,496		$	—		$	—		$	224,896
Intersegment sales	121,330			21,237			—			(142,567		)	—
Interest expense and other financing costs	2,481			3,879			—			—			6,360
Depreciation and amortization	3,989			1,547			3			—			5,539
Equity in loss from unconsolidated affiliate	584			—			—			—			584
Segment profit (loss)	4,294			(5,704		)	(231		)	—			(1,641		)
Segment assets	122,532			94,649			402			(58,062		)	159,521
Capital expenditures	8,491			4,547			66			—			13,104

Note 18—Quarterly Financial Data (Unaudited)

	Year 2004
	Quarter Ended
	March 31			June 30			September 30			December 31				Year
	(In thousands)
Revenue	$	96,146		$	100,373			$	120,796		$	120,341		$	437,656
Operating income	3,492			3,008				6,483			9,177			22,160
Net (loss) income	(620		)	(592		)		2,703			(2,406		)	(915		)
Basic net (loss) income per unit	(0.43		)	(0.42		)		1.90			(0.39		)	(0.35		)
Diluted net (loss) income per unit	(0.43		)	(0.42		)		0.98			(0.39		)	(0.35		)

F-35

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 18—Quarterly Financial Data (Unaudited) (Continued)

	Year 2003
	Quarter Ended
	March 31		June 30			September 30				December 31				Year
	(In thousands)
Revenue	$	112,130	$	90,250			$	92,931			$	89,260		$	384,571
Operating income	5,409		(2,000		)		230				3,709			7,348
Net income (loss)	3,741		(3,597		)		(3,574		)		(1,287		)	(4,717		)
Basic net income (loss) per unit	1.29		(3.93		)		(2.51		)		(0.09		)	(6.21		)
Diluted net income (loss) per unit	0.78		(3.93		)		(2.51		)		(0.09		)	(6.21		)

F-36

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS

Note 1—Organization and Basis of Presentation

Webb/Duval Gatherers (the “Partnership”), a Texas general partnership, was formed in December 1987 to provide gathering and transportation services to producers of natural gas in the South Texas region. The Partnership owns three pipeline systems, the Webb/Duval Gathering System, the Olmitos Gathering System and the Cinco Compadres Gathering System. In February 2002, Copano/Webb-Duval Pipeline, L.P. (“CWDPL”) (formerly Copano/Webb-Duval Pipeline, Inc.), a wholly owned indirect subsidiary of Copano Energy, L.L.C. (“CE”) (formerly Copano Energy Holdings, L.L.C.), increased its ownership interest in the Partnership from a 15% general partnership interest to a 62.5% general partnership interest. As a result of CWDPL’s acquisition of this additional 47.5% general partnership interest in the Partnership, CWDPL assumed operations of the Partnership from the previous operator on February 1, 2002. The remaining partners, that have substantive participating rights with respect to the management of the Partnership, collectively own a 37.5% general partnership interest in the Partnership.

The accompanying financial statements include the assets, liabilities and results of operations of the Partnership as of December 31, 2004 and 2003 and for the year ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002. A full year presentation is not practicable for 2002 because, as discussed above, CWDPL only became the operator of the Partnership on February 1, 2002.

Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although, management believes the estimates are appropriate; actual results can differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include certificates of deposit with maturities of three months or less at the time of purchase.

Concentration and Credit Risk

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable.

The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

F-42

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Allowance for Doubtful Accounts

The Partnership extends credit to customers and other parties in the normal course of business. Estimated losses on accounts receivable, if any, are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, the Partnership makes judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. Management of the Partnership has established various procedures to manage its credit exposure, including initial credit approvals, credit limits and rights of offset. The Partnership may also use prepayments and guarantees to limit credit risk to ensure that management’s established credit criteria are met. As of December 31, 2004 and 2003, the Partnership has not established an allowance for doubtful accounts.

Property and Equipment

Property and equipment consist of gas gathering systems and other related facilities, which are carried at cost less accumulated depreciation. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of assets. The Partnership calculates depreciation using the straight-line method principally over 15-year and 30-year estimated useful lives of the Partnership’s assets. The weighted average useful life of the Partnership’s pipeline and equipment assets is approximately 15 years.

The Partnership reviews long-lived assets for impairment whenever there is evidence that the carrying value of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. An impairment loss would be recognized when estimated future cash flows expected to result from the use of the asset and its eventual disposition is less than the asset’s carrying value. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions.

Transportation and Exchange Imbalances

In the course of transporting natural gas for others, the Partnership may receive for redelivery different quantities of natural gas than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and accounts receivable from affiliates and imbalance payables are included in accounts payable and accounts payable to affiliates on the balance sheets and are valued at estimated settlement prices or marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2004 and 2003, the Partnership had imbalance receivables totaling $1,850,697 and $2,202,902 (unaudited), respectively, and imbalance payables totaling $2,003,253 and $3,464,856 (unaudited), 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 either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

F-43

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligation

Under the implementation guidelines of SFAS No. 143, the Partnership has reviewed its long-lived assets for asset retirement obligation (“ARO”) liabilities and identified any such liabilities. These liabilities include ARO liabilities related to (i) rights-of-way and easements over property not owned by the Partnership and (ii) regulatory requirements triggered by the abandonment or retirement of certain of these assets.

As a result of the Partnership’s analysis of AROs, the Partnership determined it was not required to recognize any such potential liabilities. The Partnership’s rights under its easements are renewable or perpetual and retirement action, if any, is required only upon nonrenewal or abandonment of the easements. The Partnership currently expects to continue to use or renew all such easement agreements and to use these properties for the foreseeable future. Accordingly, management is unable to reasonably estimate and record liabilities for its obligations that fall under the provisions of SFAS No. 143 because it does not believe that any of the applicable assets will be retired or abandoned in the foreseeable future. The Partnership will record AROs in the period in which the obligation may be reasonably estimated.

Revenue Recognition

The Partnership’s natural gas and condensate sales are recognized in the period when the physical product is delivered to the customer at contractually agreed-upon pricing.

Transportation revenue is recognized in the period when the service is provided.

Derivatives

SFAS No. 133, as amended, “Accounting for Derivative Instruments and Hedging Activities,” establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term.

F-44

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 2—Summary of Significant Accounting Policies (Continued)

Income Taxes

The Partnership is not a taxpaying entity for federal and state income tax purposes and, accordingly, does not recognize any expense for such taxes. The income tax liability resulting from the Partnership’s operations is the responsibility of the individual general partners of the Partnership. In the event of an examination of the Partnership’s tax return, the tax liability of the individual general partners could be changed if an adjustment of the Partnership’s income or loss is ultimately sustained by the taxing authorities.

Note 3—New Accounting Pronouncements

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

Note 4—Property and Equipment

Property and equipment consisted of the following:

	December 31,
	2004			2003
				(unaudited)
Property and equipment, at cost:
Pipelines and equipment	$	25,143,074		$	24,777,023
Construction in progress	60,625			16,009
	25,203,699			24,793,032
Less accumulated depreciation and amortization	(16,920,364		)	(16,267,234		)
Total property and equipment, net	$	8,283,335		$	8,525,798

Note 5—Risk Management Activities

The Partnership may utilize a hedging strategy to mitigate the risk of the volatility of natural gas prices in connection with the purchase or sale of natural gas with respect to the resolution of its natural gas imbalance positions. However, for the years ended December 31, 2004 and 2003 (unaudited) and for the period from February 1, 2002 through December 31, 2002, no such hedging positions were purchased or exercised and no option positions were outstanding as of December 31, 2004 or 2003 (unaudited).

F-45

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 6—Related Party Transactions

Operations Services

The Partnership does not directly employ any persons to manage or operate its business. Through December 31, 2004, Copano/Operations, Inc. (“Copano Operations”), an entity controlled by Mr. John R. Eckel, Jr., Chairman of the Board of Directors and Chief Executive Officer of CE, provided these management and operations support services as well as administrative support services to CWDPL, the operator of the Partnership. Effective January 1, 2005, Copano Operations transferred responsibility to CPNO Services, L.P., an indirect wholly owned subsidiary of CE, for a significant portion of the services that Copano Operations had previously provided to CWDPL. CWDPL reimburses Copano Operations for all direct and indirect costs of services provided by Copano Operations. CWDPL charges the Partnership for operations and support services as well as a monthly administrative fee of $16,000 and is reimbursed by the Partnership for certain personnel services not included in the administrative fee. Additionally, CWDPL has made advances to WDG for capital expenditures. For the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, CWDPL charged the Partnership $711,593, $619,743 (unaudited) and $478,004, respectively, for administrative fees and operations and support services including payroll and benefits expense for both field and administrative personnel of the Partnership and capitalized costs. As of December 31, 2004 and 2003, the Partnership’s net payable to CWDPL totaled $940,928 and $718,217 (unaudited), respectively.

Management estimates that these expenses on a stand-alone basis (that is, the cost that would have been incurred by the Partnership to conduct current operations if the Partnership had obtained these services from an unaffiliated entity) would not be less favorable than the amounts recorded in the Partnership’s financial statements for the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002.

Natural Gas Transportation and Exchange Imbalance Transactions

Pursuant to a gas gathering agreement, the Partnership earned transportation fees of $492,590, $180,928 (unaudited) and $91,274 from Copano Field Services/Agua Dulce (“CFS/AD”), an indirect wholly owned subsidiary of CE and an affiliate of CWDPL, during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. The Partnership recorded natural gas sales of $1,330,993, $913,332 (unaudited) and $1,220,498 pursuant to the imbalance cash out provisions of the gas gathering agreement with CFS/AD during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. Additionally, the Partnership recorded cost of natural gas sold of $1,135,402, $459,860 (unaudited) and $0 pursuant to the cash out provisions of the gas gathering agreement with CFS/AD for the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. As of December 31, 2004, the Partnership owed CFS/AD $200,406 under this gas gathering agreement and as of December 31, 2003, CFS/AD owed the Partnership $53,190 (unaudited) under this gas gathering agreement.

Pursuant to gas purchase and sales agreements, the Partnership sold natural gas to other affiliates of CWDPL and indirect wholly owned subsidiaries of CE of $787,117 and $40,833 (unaudited) and $0 during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. Additionally, the Partnership recorded cost of natural gas sold to these other affiliates of CWDPL of $550,733, $9,571 (unaudited) and $0 during the years ended December 31,

F-46

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 6—Related Party Transactions (Continued)

2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. The Partnership also earned transportation fees from these other affiliates of CWDPL of $1,575, $0 (unaudited) and $0 during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively.

Pursuant to gas gathering agreements with the other general partners of the Partnership, the Partnership earned transportation fees of $146,647 and $104,570 (unaudited) and $93,077 during the years ended December 31, 2004 and 2003 and for period from February 1, 2002 through December 31, 2002, respectively. Additionally, under one of the other general partner’s gas gathering agreement, the Partnership recorded gas imbalance activity as cost of natural gas sold of $(111,288), $438,368 (unaudited) and $60,220 during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. Under one of the other general partner’s gas gathering agreement, the Partnership had net purchases of natural gas of $41,752, $0 (unaudited) and $0 during the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, respectively. As of December 31, 2004 and 2003, these general partners owed the Partnership $41,973 and $16,745 (unaudited), respectively, for transportation fees. Additionally one of these general partners paid a well connection fee of $23,000 during the year ended December 31, 2004. The Partnership had net gas imbalance obligations to these general partners of $755,915 and $866,691 (unaudited) as of December 31, 2004 and 2003, respectively.

Management of the Partnership believes these transactions were on terms no less favorable than those that could have been achieved with an outside company.

Note 7—Business Segment and Customer Information

Based on its management approach, the Partnership believes that all of its material operations revolve around the gathering and transportation of natural gas and it currently reports its operations, both internally and externally, as a single business segment. The Partnership had two affiliated customers and one third-party customer that accounted for 40%, 17% and 15%, respectively, of its revenue for the year ended December 31, 2004. The Partnership had one (unaudited) affiliated customer and one (unaudited) third-party customer that accounted for 34% (unaudited) and 27% (unaudited), respectively, of its revenue for the year ended December 31, 2003. The Partnership had one affiliated customer and one third-party customer that accounted for 54% and 17%, respectively, of its revenue for the period from February 1, 2002 through December 31, 2002.

Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had one third-party and two affiliated suppliers during the year ended December 31, 2004 that accounted for 38%, 34% and 17%, respectively, of its cost of natural gas sold. Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had one (unaudited) third-party supplier and one (unaudited) affiliated supplier for the year ended December 31, 2003 that accounted for 78% (unaudited) and 21% (unaudited), respectively, of its cost of natural gas sold. Excluding changes in the gas imbalances recorded as cost of natural gas sold, the Partnership had one third-party supplier during the period from February 1, 2002 through December 31, 2002 that accounted for 100% of its cost of natural gas sold. The Partnership only buys and sells natural gas in connection with the resolution of natural gas imbalances incurred as a result of its gathering and transportation activities.

F-47

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 8—Fair Value of Financial Instruments

The carrying amount of cash equivalents is believed to approximate its fair value because of the short maturities of these instruments.

Note 9—Commitments and Contingencies

Commitments

For the years ended December 31, 2004 and 2003 and for the period from February 1, 2002 through December 31, 2002, rental expense for leased vehicles and leased compressors and related field equipment used in the Partnership’s operations totaled $180,269, $186,950 (unaudited) and $67,608. As of December 31, 2004, commitments under the Partnership’s lease obligations totaled $13,704 for 2005, $8,394 for 2006 and $700 for 2007.

Although the Partnership may have both fixed and variable contractual commitments arising in the ordinary course of its activities, as of December 31, 2004, the Partnership had no fixed or variable contractual commitments to purchase or sell natural gas.

Guarantees

In November 2002, the FASB issued Interpretation No (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In certain instances, this interpretation requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.

FIN 45 also sets forth disclosure requirements for guarantees including the guarantees by a general partner of the Partnership on behalf of the Partnership. As of December 31, 2004, no parental guarantees by the general partners are outstanding. However, from July 8, 2002 through April 1, 2004, subsidiaries of CE guaranteed certain vehicle lease obligations of Copano Operations for vehicles operated for the benefit of the Partnership and certain subsidiaries of CE. Effective April 2, 2004, the vehicle lease was transferred to a subsidiary of CE, as lessee. As of December 31, 2004, certain other subsidiaries of CE guaranteed approximately $170,000 of the lessee’s lease payment obligations (approximately $22,798 relates to vehicles used by the Partnership). Additionally, under each vehicle lease, the lessee has guaranteed the lessor a minimum residual sales value upon the expiration of the lease and sale of the underlying vehicle. These residual sale values guaranteed by the lessee are in turn guaranteed by certain other subsidiaries of CE. At December 31, 2004, guaranteed residual values for vehicles used by the Partnership under these operating leases were as follows:

	2005		2006		2007		2008		Thereafter			Total
Lease residual values	$	43,418	$	—	$	13,654	$	—		$	—	$	57,072

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

Regulatory Compliance

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

F-48

WEBB/DUVAL GATHERERS
NOTES TO FINANCIAL STATEMENTS—(Continued)

Note 9—Commitments and Contingencies (Continued)

Litigation

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

F-49

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

	Title of Each Class			Name of Exchange on which Registered
None			Not applicable

Number				Description
3.1				Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004)
3.2				Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
3.3				Second Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.3 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).
10.1				Amended and Restated Credit Agreement dated February 13, 2004 among Copano Pipelines Group, L.L.C., Copano Field Services/Copano Bay, L.P., Copano Field Services/Agua Dulce, L.P., Copano Field Services/South Texas, L.P., Copano Field Services/Upper Gulf Coast, L.P., Copano Field Services/Live Oak, L.P., Copano Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P. and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and Fleet National Bank and the other Lenders named therein (incorporated by reference to Exhibit 10.1 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.2				First Amendment to Amended and Restated Credit Agreement dated as of March 15, 2004, among Copano Pipelines Group, L.L.C., Copano Field Services/Copano Bay, L.P., Copano Field Services/Agua Dulce, L.P., Copano Field Services/South Texas, L.P., Copano Field Services/Upper Gulf Coast, L.P., Copano Field Services/Live Oak, L.P., Copano Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P. and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and Fleet National Bank and the other Lenders named therein (incorporated by reference to Exhibit 10.2 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.3				Second Amendment to Amended and Restated Credit Agreement dated as of November 15, 2004, among Copano Pipelines Group, L.L.C., Copano Field Services/ Copano Bay, L.P., Copano Field Services/Agua Dulce, L.P., Copano Field Services/ South Texas, L.P., Copano Field Services/Upper Gulf Coast, L.P., Copano Field Services/Lice Oak, L.P., Copano Field Services/Central Gulf Coast, L.P., Copano Pipelines/South Texas, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P., and Copano Energy Services/Upper Gulf Coast, L.P., as the Borrowers, and Fleet National Bank and the other Lenders named therein (incorporated by reference to Exhibit 10.3 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).

10.4		Credit Agreement dated as of November 15, 2004, by and among Copano Houston Central, L.L.C., Copano Processing, L.P. and Copano NGL Services, L.P. as the Borrowers and Comerica Bank as the Lender (incorporated by reference to Exhibit 10.4 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).
10.5		Form of Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to Amendment No. 3 to Registration Statement on Form S-1/A filed October 26, 2004).
10.6		Stakeholders’ Agreement dated July 30, 2004, by and among Copano Energy, L.L.C., Copano Partners, L.P., R. Bruce Northcutt, Matthew J. Assiff, EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., CEH Holdco, Inc., CEH Holdco II, Inc., DLJ Merchant Banking Partners III, L.P., DLJ Offshore Partners III, C.V., DLJ Offshore Partner III-1, C.V., DLJ Offshore Partners III-2, C.V., DLJ Merchant Banking III, Inc., DLJ MB Partners III GmbH & Co, KG, Millennium Partners II, L.P. and MBP III Plan Investors, L.P. (incorporated by reference to Exhibit 10.6 to Registration Statement on Form S-1 filed July 30, 2004).
10.7†		Amended and Restated Gas Processing Contract dated as of January 1, 2004, between Kinder Morgan Texas Pipeline, L.P. and Copano Processing, L.P. (incorporated by reference to Exhibit 10.7 to Amendment No. 6 to Registration Statement on Form S-1/A filed November 5, 2004).
10.8		Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated April 9, 2003 (incorporated by reference to Exhibit 10.8 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.9		First Amendment to Employment Agreement between Copano/Operations, Inc., R. Bruce Northcutt and the Copano Controlling Entities, dated July 30, 2004 (incorporated by reference to Exhibit 10.9 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.10*		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.
10.11*		Second Amendment to Employment Agreement between CPNO Services, L.P., R. Bruce Northcutt and the Copano Controlling Entities, effective March 1, 2005.
10.12		Employment Agreement between Copano/Operations, Inc. and James J. Gibson, III, dated as of October 1, 2004 (incorporated by reference to Exhibit 10.10 to Amendment No. 4 to Registration Statement on Form S-1/A filed November 2, 2004).
10.13*		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. and James J. Gibson, III.
10.14*		First Amendment to Employment Agreement between CPNO Services, L.P. and James J. Gibson, III, effective March 1, 2005.
10.15		Lease Agreement dated August 14, 2003 between Mateo Lueia and Copano Field Services/Agua Dulce, L.P. (incorporated by reference to Exhibit 10.11 to Amendment No. 2 to Registration Statement on Form S-1/A filed October 12, 2004).
10.16		Lease Agreement dated January 22, 2003 between Copano/Operations, Inc., Copano Processing, L.P., Copano Pipelines/Upper Gulf Coast, L.P., Copano Pipelines/Hebbronville, L.P. and Copano Field Services/Central Gulf Coast, L.P. and American General Life Insurance Company (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to Registration Statement on Form S-1 filed October 12, 2004).

10.17		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).
10.18		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).
10.19		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).
10.20		Form of Restricted Unit Grant (Directors) (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed December 15, 2004).
10.21		Form of Grant of Options (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q filed December 21, 2004).
10.22		Form of Restricted Unit Grant (Employees) (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-8 filed February 11, 2005).
10.23		Form of Unit Option Grant under the Copano Energy, L.L.C. Long-Term Incentive Plan. (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-8 filed February 11, 2005).
10.24		Administrative and Operating Services Agreement dated November 15, 2004, among Copano/Operations, Inc. and Copano Energy, L.L.C., and the Copano Operating Subsidiaries listed therein (incorporated by reference to Exhibit 3.4 to Post-Effective Amendment No. 1 to Registration Statement on Form S-1/A filed December 15, 2004).
10.25		Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed March 2, 2005).
10.26		2005 Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed March 2, 2005).
21.1*		List of Subsidiaries.
23.1*		Consent of Deloitte & Touche LLP
31.1*		Sarbanes-Oxley Section 302 certification of John R. Eckel, Jr. (Chief Executive Officer) for Copano Energy, L.L.C.
31.2*		Sarbanes-Oxley Section 302 certification of Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.
32.1*		Sarbanes-Oxley Section 906 certification of John R. Eckel, Jr. (Chief Executive Officer) for Copano Energy, L.L.C.
32.2*		Sarbanes-Oxley Section 906 certification of Matthew J. Assiff (Chief Financial Officer) for Copano Energy, L.L.C.

	Title of Class
Common Units Representing Limited Liability Company Interests

		Page
Part I
Item 1.	Business	1
Item 2.	Properties	21
Item 3.	Legal Proceedings	21
Item 4.	Submission of Matters to a Vote of Security Holders	21
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	54
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	54
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	55
Part III
Item 10.	Directors and Executive Officers of the Registrant	56
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	56
Item 13.	Certain Relationships and Related Transactions	56
Item 14.	Principal Accountant Fees and Services	56
Part IV
Item 15.	Exhibits and Financial Statement Schedules	57

	COPANO ENERGY, L.L.C.
	By:	/s/ JOHN R. ECKEL, JR.
		John R. Eckel, Jr.
		Chairman of the Board of Directors and Chief Executive Officer
	By:	/s/ MATTHEW J. ASSIFF
		Matthew J. Assiff
		Senior Vice President and Chief Financial Officer

	Signature		Title		Date
/s/ JOHN R. ECKEL, JR.		Chairman of the Board of Directors and		March 31, 2005
John R. Eckel, Jr.		Chief Executive Officer (Principal Executive Officer)
/s/ MATTHEW J. ASSIFF		Senior Vice President and Chief Financial Officer		March 31, 2005
Matthew J. Assiff		(Principal Financial Officer)
/s/ LARI PARADEE		Vice President and Controller (Principal Accounting		March 31, 2005
Lari Paradee		Officer)
/s/ ROBERT L. CABES, JR.		Director		March 31, 2005
Robert L. Cabes, Jr.
/s/ JAMES G. CRUMP		Director		March 31, 2005
James G. Crump
/s/ ERNIE L. DANNER		Director		March 31, 2005
Ernie L. Danner
/s/ MICHAEL L. JOHNSON		Director		March 31, 2005
Michael L. Johnson
/s/ SCOTT A. GRIFFITHS		Director		March 31, 2005
Scott A. Griffiths
/s/ T. WILLIAM PORTER III		Director		March 31, 2005
T. William Porter III
/s/ WILLIAM L. THACKER		Director		March 31, 2005
William L. Thacker

	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, 2004 and 2003		F-3
Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002		F-5
Consolidated Statements of Members’ Capital and Comprehensive Loss for the years ended December 31, 2004, 2003 and 2002		F-6, F-7
Notes to the Consolidated Financial Statements		F-8
Webb/Duval Gatherers Financial Statements:
Report of Independent Registered Public Accounting Firm		F-37
Balance Sheets as of December 31, 2004 and 2003 (unaudited)		F-38
Statements of Operations for the years ended December 31, 2004 and 2003 (unaudited) and for the period from February 1, 2002 through December 31, 2002		F-39
Statements of Cash Flows for the years ended December 31, 2004 and 2003 (unaudited) and for the period from February 1, 2002 through December 31, 2002		F-40
Statements of Partners’ Capital for the years ended December 31, 2004 and 2003 (unaudited) and for the period from February 1, 2002 through December 31, 2002		F-41
Notes to Financial Statements		F-42

	Year Ended December 31,					Period From February 1, 2002 through December 31,
	2004		2003			2002
			(unaudited)
Revenue:
Natural gas sales	$	330,919	$	475,428		$	84,093
Natural gas sales to affiliates	2,144,428		954,165			1,220,498
Transportation and gathering fees	1,018,399		1,040,478			184,351
Transportation and gathering fees from affiliates	640,812		285,498			768,057
Condensate sales	421,169		424,279			178,833
Other	26,264		—			—
Other—affiliate	23,000		—			—
Total revenue	4,604,991		3,179,848			2,435,832
Costs and expenses:
Cost of natural gas sold	575,735		960,607			2,199,403
Cost of natural gas—affiliates	1,642,916		907,799			60,220
Operations and maintenance	853,057		711,537			407,306
Depreciation and amortization	654,929		591,215			525,686
General and administrative	315,536		275,494			243,140
Taxes other than income	116,518		160,942			140,967
Total cost and expenses	4,158,691		3,607,594			3,576,722
Net income (loss)	$	446,300	$	(427,746	)	$	(1,140,890	)

Balance, February 1, 2002	$	8,516,456
Net loss	(1,140,890		)
Balance, December 31, 2002	7,375,566
Net loss (unaudited)	(427,746		)
Balance, December 31, 2003 (unaudited)	6,947,820
Net income	446,300
Balance, December 31, 2004	$	7,394,120