You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited consolidated financial statements and notes thereto included elsewhere in this report.

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

 Bbls/d:         Barrels per day
 Btu:            British thermal units
 MMBtu:          One million British thermal units
 MMBtu/d:        One million British thermal units per day
 Mcf/d:          One thousand cubic feet 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

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. Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission pipeline assets and natural gas processing facilities in Oklahoma, Texas, Wyoming and Louisiana.

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments:
Oklahoma, Texas and Rocky Mountains.

• Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering and related compression, dehydration and nitrogen rejection services and natural gas processing. This segment also includes a crude oil pipeline located in south Oklahoma and north Texas. For the three months ended September 30, 2008 and 2007, this segment generated approximately 54% and 52%, respectively, of our total segment gross margin, which is defined below under "- How We Evaluate Our Operations." For the nine months ended September 30, 2008 and 2007, this segment generated approximately 60% and 55%, respectively, of our total segment gross margin.

• Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration and marketing. Our Texas segment also provides natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central plant, Sheridan NGL pipeline and Brenham NGL pipeline. In addition, we are constructing a treating and processing plant in Montague County, Texas, and our Texas segment owns a processing plant located in southwest Louisiana. For the three months ended September 30, 2008 and 2007, this segment generated approximately 67% and 58%, respectively, of our total segment gross margin. For the nine months ended September 30, 2008 and 2007, this segment generated approximately 63% and 56%, respectively, of our total segment gross margin.

• Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. The Rocky Mountains segment was established with our acquisition of Cantera in October 2007. This segment generated approximately 2% of our total segment gross margin for each of the three and nine months ended September 30, 2008. The gross margin generated by this segment is derived from the services we provide to our Rocky Mountains producers and does not include results associated with our interests in Bighorn or Fort Union, which are reported as equity in earnings from unconsolidated affiliates.

Corporate and other relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments. For the three months ended September 30, 2008 and 2007, corporate and other generated approximately (23)% and (10)%, respectively, of our total segment gross margin. For the nine months ended September 30, 2008 and 2007, corporate and other generated approximately
(25)% and (11)%, respectively, of our total segment gross margin.

Recent Developments

McMullen Lateral Acquisition. In September 2008, we signed a definitive purchase agreement with Williams' Transco subsidiary to acquire the McMullen Lateral pipeline, a 151-mile, 24-inch pipeline extending from McMullen County, Texas, to Wharton County, Texas. Our Board of Directors has also approved construction projects designed to integrate the McMullen Lateral with our existing facilities, provide McMullen Lateral shippers access to numerous third party pipelines, including Transco, and also to provide an additional residue gas outlet for our Houston Central processing plant. The purchase price for the McMullen Lateral is $42.5 million, and we anticipate that the combined costs of the acquisition and related construction projects will total approximately $110 million. Closing of the transaction is subject to receipt of necessary and requested FERC authorizations. We expect that a filing with FERC will be made during the fourth quarter of 2008. We plan to finance the transaction and related projects with cash from operations, cash on hand and borrowings under our Credit Facility. Subject to FERC approval, we anticipate making these capital expenditures primarily in 2009 and 2010.

St. Jo Processing Plant. To address increased drilling activity in north Texas, we are constructing a treating and processing plant in Montague County, Texas, which we refer to as our St. Jo processing plant. During the construction period, we are operating a leased refrigeration processing plant and an amine treating facility, which were placed in service in May 2008. We estimate that our permanent cryogenic processing plant, which will initially be configured for 50 MMcf/d inlet capacity and will include a 1,200 GPM amine treating facility, will be in service in the second quarter of 2009.

Fort Union Expansion. The final phase of Fort Union's pipeline expansion, which increased capacity to approximately 1.2 Bcf/d, was placed in service on July 25, 2008. Fort Union has begun an expansion of its amine treating facility at Medicine Bow, Wyoming. The first phase of the expansion is expected to be operational in November 2008 and will increase treating capacity to 900 GPM. A second phase is expected to be operational in December 2008 and will increase treating capacity by an additional 600 GPM for a total treating capacity of 1,500 GPM.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with "- How We Evaluate Our Operations" and "- How We Manage Our Operations" below. Many of the factors affecting our business are beyond our control and are difficult to predict. Please read "Item 1A. Risk Factors" for a description of these factors and related risks.

Credit and Capital Market Disruptions. Multiple events during 2008 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations to provide liquidity to the financial sector, capital markets currently remain constrained. To the extent we access debt or equity markets in the near term, we believe that our ability to raise debt and equity at prices similar to our recent offerings will be limited so long as capital markets remain constrained.

Commodity Prices and Producer Activity. Our gross margins and distributable cash flow are influenced by the prices of natural gas and NGLs, and by drilling activity in our operating regions. Generally, prices affect our Texas and Oklahoma segments directly and our Rocky Mountains segment only indirectly. Please read "- How We Evaluate Our Operations" and "- How We Manage Our Operations" for further discussion.

Commodity prices have been particularly volatile in 2008 and have declined significantly since reaching historic highs in July 2008. For example, first of the month prices on CenterPoint East, one of the indices we use for

Oklahoma natural gas prices, ranged from a high of $11.24 per MMBtu for July 2008 to a low of $2.61 per MMBtu for November 2008. Daily natural gas prices have been similarly volatile, as have NGL prices. Daily prices for our weighted-average product production mix on Conway, our principal NGL index in Oklahoma, averaged $68.20 per barrel in July 2008 and $33.35 per barrel in October 2008.

The indices we use to price natural gas and NGLs in Texas reflect similar trends. For example, first of the month natural gas prices on the Houston Ship Channel, or HSC, index ranged from $12.84 per MMBtu for July 2008 to $5.72 per MMBtu for November 2008, and daily prices for our weighted-average product production mix on Mt. Belvieu averaged $78.99 per barrel in July 2008 and $38.35 per barrel in October 2008.

We believe these adverse price changes are attributable primarily to market disruptions associated with Hurricanes Gustav and Ike, as well as the recent disruptions in the credit markets and overall downturn in the economy. In addition, the mid-continent region is experiencing oversupply of natural gas and lack of available storage, which we believe are due largely to development of natural gas from unconventional natural gas sources in surrounding regions that have not yet developed adequate takeaway capacity. If the current weakness in the economy develops into a prolonged economic recession, it would likely reduce demand for natural gas and for NGL products such as ethane, a primary feedstock for petrochemical and manufacturing industries, and result in continued lower natural gas and NGL prices.

Each of our segments is affected by the level of drilling in its operating area. Commodity price fluctuations and access to capital influence natural gas producers as they schedule drilling projects, which, in turn, affect the volumes of natural gas on our pipelines. In an environment of lower natural gas prices, producers typically re-evaluate their drilling schedules and related capital expenditures. The current pricing environment, particularly in combination with the constrained capital and credit markets and overall economic downturn, could lead to a decline in drilling activity.

For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our earnings and cash flow, please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

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: (i) throughput volumes;
(ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) distributable cash flow and total distributable cash flow.

Throughput Volumes. Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes delivered to our plants and moving through our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is significantly influenced by the volume of natural gas delivered to the plant, the NGL content of the natural gas and the recovery capability of the processing plant. 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.

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

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

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

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

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

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

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

To measure the overall financial impact of our company's contract portfolio, we use total segment gross margin, which is the sum of our operating segments' gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and
(v) our risk management activities. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon the market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

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

Operations and Maintenance Expenses. The most significant portion of our operations and maintenance expenses consists of direct labor, insurance, repair and maintenance, utilities and contract services. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. A portion of our operations and maintenance expenses is incurred through Copano Operations, an affiliate of our company controlled by John R. Eckel, Jr., the Chairman of our Board of Directors and our Chief Executive Officer. See Note 9 of the notes to the unaudited financial statements included in Item 1 of this report. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the operations and maintenance expenses it incurs on our behalf, which consist primarily of payroll costs. We monitor

operations and maintenance expenses to assess the impact of such costs on the profitability of a particular asset or group of assets and to evaluate the efficiency of our operations.

General and Administrative Expenses. Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. A portion of our general and administrative expenses are incurred through Copano Operations, an affiliate of our company. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the general and administrative expenses it incurs on our behalf. To help ensure the appropriateness of our general and administrative expenses, we monitor such expenses through comparison with general and administrative expenses incurred by similar midstream companies and with the annual financial plan approved by our Board of Directors.

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

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

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

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

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

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

EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to our lenders and is used to compute financial covenants under our Credit Facility. Neither EBITDA nor Adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

Distributable Cash Flow and Total Distributable Cash Flow. We define distributable cash flow as net income plus: (i) depreciation and amortization expense (but not amortization expense relating to our commodity hedging instruments); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates;
(iii) the subtraction of maintenance capital expenditures, (iv) the subtraction of equity in earnings from unconsolidated affiliates and (v) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and, beginning with the third quarter of 2008, our line fill contributions to third-party pipelines and gas imbalances. Although this adjustment was not made in previously reported quarters, management believes this adjustment is appropriate as these items reflect unrealized gains or losses related to contractual obligations that are not currently settled in cash. 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. Prior to the first quarter of 2008, we also

included in distributable cash flow reimbursements by our pre-IPO investors of certain general and administrative expenses in excess of the "G&A Cap" defined in our limited liability company agreement. The G&A Cap expired at the end of 2007; therefore we no longer include such reimbursements in distributable cash flow.

Distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly traded partnerships and limited liability companies because the market value of a unit of such an entity is significantly influenced by the amount of cash distributions the entity can pay to a unitholder.

We define total distributable cash flow as distributable cash flow plus the amortization expense relating to our commodity derivative instruments and, like distributable cash flow, indicates sustainability of quarterly distribution rates. Our management and board of directors, as well as many in the investment community, consider total distributable cash flow as an important measure of the rate at which cash available for distribution is generated by our operations.

Neither distributable cash flow nor total distributable cash flow should be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

How We Manage Our Operations

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

Economic Models and Standardized Processing Margin. We utilize our economic models to determine (i) whether we should reduce the ethane extracted from certain natural gas processed by some of our processing plants and (ii) whether we should process or condition natural gas at our Houston Central plant.

To isolate and consistently track changes in commodity price relationships and their impact on our Texas segment's results from its processing operations, we calculate a hypothetical "standardized" processing margin at our Houston Central plant. 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 the current operating commodity price environment of our Texas processing operations 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 $0.56 per gallon during the third quarter of 2008 compared to $0.54 per gallon during the third quarter of 2007. Our standardized processing margins averaged $0.57 per gallon during the nine months ended September 30, 2008 compared to $0.36 per gallon during the nine months ended September 30, 2007. The average standardized processing margin for the period from January 1, 1989 through September 30, 2008 is $0.14 per gallon.

Flow and Transaction Monitoring Systems. We utilize automated systems that track commercial activity on each of our Texas segment pipelines and monitor the flow of natural gas on all of our pipelines. For our Oklahoma segment, we . . .