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:

 /d:             Per day
 Bcf:            One billion cubic feet
 Btu:            One British thermal unit
 Lean Gas:       Natural gas that is low in NGL content
 MMBtu:          One million British thermal units
 Mcf:            One thousand cubic feet
 MMcf:           One million cubic feet
 NGLs:           Natural gas liquids, which consist primarily of ethane, propane,
                 isobutane, normal butane, natural gasoline and stabilized
                 condensate
 Residue gas:    The pipeline quality natural gas remaining after natural gas is
                 processed
 Rich gas:       Natural gas that is high in NGL content
 Throughput:     The volume of natural gas or NGLs 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, natural gas processing and fractionation facilities, NGL pipelines and, through September 2009, a crude oil pipeline. We operate 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 transmission of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome, and through September 2009, included a crude oil pipeline located in south Oklahoma and north Texas.

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

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

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

Trends and Uncertainties

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

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are influenced by the prices of natural gas and NGLs, and by drilling activity. Generally, prices affect the cash flow and profitability of our Texas and Oklahoma segments

directly. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly. Please read "- How We Evaluate Our Operations" and "- How We Manage Our Operations" for further discussion. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

The long term growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives, capital and adequate returns for producers to maintain and increase natural gas exploration and production. Commodity price fluctuations and the availability of capital are among the factors that influence natural gas producers as they schedule drilling projects. Low natural gas prices, particularly in combination with high operating costs, act as a disincentive to producers. In an unfavorable pricing environment, producers typically re-evaluate their drilling schedules and related capital expenditures and, depending on the severity and duration of the pricing trends, may suspend drilling and completion of wells to the degree they have become uneconomic. We believe that future natural gas prices will be influenced by regional drilling activity takeaway capacity, the severity of winter and summer weather, natural gas storage levels, liquefied natural gas imports, NGL transportation and fractionation capacity and the overall economy.

The financial and economic crises of late 2008 were accompanied by sharp declines in prices for oil, natural gas and NGLs. Prices for oil and NGLs have continued the recovery that began in the second quarter of 2009, while natural gas prices showed some improvement but remained low. Forward pricing on NYMEX reflects market expectations that oil and natural gas prices in the coming months will be consistently higher compared to recent months. While recent economic indicators increasingly support the view that the recession has ended, the strength and sustainability of an economic recovery remain uncertain. A renewed slowdown in economic activity would likely result in continued lower natural gas prices and renewed declines in NGL prices, which in turn would delay a recovery in drilling activity.

Pricing Trends in Texas. During the third quarter of 2009, NGL prices in Texas continued to recover, and natural gas prices declined. Prices for both natural gas and NGLs have improved for the fourth quarter 2009 to date. The first-of-the-month price for natural gas on the Houston Ship Channel index was $4.23 per MMBtu for November 2009, and average month-to-date prices for NGLs at Mt. Belvieu through November 2, 2009 were $43.23 per barrel. The following graph and table summarize monthly and quarterly average prices on the primary indices we use to price natural gas and NGLs in Texas.

(1) NGL prices for November are month-to-date through November 2, 2009. Average monthly NGL prices are calculated based on our weighted-average product production mix at Mt. Belvieu for the period indicated. Average monthly NGL prices for October and November are based on our third-quarter-weighted average production mix.

                                                                                      Quarterly Data for Texas:
                                               Q1 2008         Q2 2008         Q3 2008         Q4 2008          Q1 2009        Q2 2009         Q3 2009
Houston Ship Channel ($/MMBtu)               $    7.73       $   10.58       $    9.98       $    6.37        $    4.21      $    3.44       $    3.32
Mt. Belvieu ($/barrel)                       $   58.94       $   68.89       $   69.12       $   35.70        $   25.81      $   30.12       $   35.09
Texas Service Throughput (MMBtu/d)             696,658         700,545         666,686         679,142          644,752        630,674         613,234
Texas Plant Inlet (MMBtu/d)                    601,736         629,334         596,225         600,719          558,115        559,597         543,994
Texas Segment Gross Margin (in thousands)    $  41,576       $  40,499       $  41,392       $  19,256        $  20,580      $  23,320       $  26,875

Oklahoma Prices. During the third quarter of 2009, Oklahoma NGL prices continued to recover from the lows experienced in the first quarter, and natural gas prices improved initially but declined in September. Natural gas prices have recovered during the first part of the fourth quarter, and NGL prices have continued to strengthen. The first of month price for natural gas on CenterPoint East was $4.22 per MMBtu for November, and month-to-date average prices for NGLs at Conway through November 2, 2009 were $39.42 per barrel. The following graph and table summarize the average monthly and quarterly prices on the primary indices we use to price natural gas and NGLs in Oklahoma.

(1) NGL prices for November are month-to-date through November 2, 2009. Average monthly NGL prices are calculated based on our weighted-average product production mix at Conway for the period indicated. Average monthly NGL prices for October and November are based on our third quarter weighted-average production mix. Segment gross margin results exclude activities attributable to our crude oil pipeline and related assets. See Item 1, Note 13 to our unaudited consolidated financial statements entitled "Discontinued Operations."

                                                                                       Quarterly Data for Oklahoma:
                                                  Q1 2008         Q2 2008         Q3 2008         Q4 2008          Q1 2009        Q2 2009         Q3 2009
CenterPoint East ($/MMBtu)                      $    7.20       $    9.26       $    8.41       $    3.58        $    3.37      $    2.70       $    2.98
Conway ($/barrel)                               $   56.33       $   62.27       $   59.42       $   27.36        $   24.13      $   25.57       $   27.62
Oklahoma Service Throughput (MMBtu/d)             222,006         228,941         243,000         261,107          271,222        267,576         260,296
Oklahoma Plant Inlet (MMBtu/d)                    150,060         155,430         158,047         160,074          160,181        166,846         166,884
Oklahoma Segment Gross Margin (in thousands)    $  35,637       $  46,284       $  33,132       $  18,122        $  14,300      $  17,472       $  18,284

NGL Basis Trends. While NGL prices at both Mt. Belvieu and Conway improved during the third quarter, the rate of improvement on Mt. Belvieu was faster than at Conway. As a result, we experienced a widening basis differential affecting NGL prices during the third quarter, which in August reached $9.95 per barrel. However, Conway prices for September and the beginning of the fourth quarter have indicated a reversal of this trend. At November 2, 2009 the basis differential between Mt. Belvieu and Conway had narrowed to $2.87 per barrel.

Trends in Drilling and Production Activity. Drilling activity has continued to be lower due to the weaker pricing environment. We experienced a modest decrease in overall volumes compared to the third quarter of 2008, largely due to lower volumes in Texas and modestly lower volumes in the Rocky Mountains (including Bighorn and Fort Union). These volume decreases are attributable partly to lower drilling activity; however, a decrease in low-margin gas from a third party pipeline was also a significant factor in Texas. Compared to the second quarter of 2009, third quarter volumes reflect modest decreases in Texas and Oklahoma, while Rocky Mountains volumes (including Bighorn and Fort Union) remained flat. Although commodity prices and financial market conditions have begun to recover, improvements in drilling activity remain sporadic, and it remains unclear when producers will undertake sustained increases in drilling activity throughout the areas in which we operate.

We anticipate that producers may increase new drilling activity once natural gas prices reach a level sufficient to make drilling and production economic. The level at which drilling and production become economic depends on various factors, including the producer's drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir, among other things. While these costs have declined significantly since late 2008, additional considerations, such as demand for and competing supplies of natural gas, and their anticipated effects on natural gas prices, will also influence producers' decisions regarding drilling. For producers of rich gas who share in the benefits of improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset as prices for condensate and NGLs increase. In addition, improving oil prices could lead to increased production of casinghead natural gas associated with oil production.

If the pricing environment of the third quarter of 2009 continues, we anticipate that we will see sustained or increasing drilling activity in areas that produce rich gas, for example the Eagle Ford Shale trend in South Texas, and a continued low level of drilling activity in areas that produce lean gas, for example the Woodford Shale in Oklahoma and the Powder River Basin in Wyoming. We expect that many producers of lean gas will wait to see sustained increases in natural gas prices before resuming significant drilling activity. Forward pricing on NYMEX suggest that natural gas prices could improve in the near future; however, forward curves only reflect market expectations, and it is uncertain to what extent they will influence producers' drilling decisions. Once drilling activity increases, a recovery in volumes will be subject to delays for processes involved in completing and attaching new wells. Any prolonged reduction in oil and natural gas prices would further depress the current levels of exploration, development and production activity.

Other Industry Trends. Due to higher NGL prices and the completion of projects increasing NGL output, NGL fractionation facilities are experiencing capacity constraints, which we believe could lead to erosion in the processing margins received from NGLs. For a portion of the third quarter of 2009, we realized lower revenue for sales of mixed NGLs from the tailgate of our Houston Central plant under a short term pricing arrangement. If NGL fractionation capacity remains constrained, the effect on NGL revenue could offset the benefits of improving NGL market prices to some extent. In August, we entered into a new contract to sell NGLs from Houston Central at a higher price. In addition, we are expanding our fractionation capacity at Houston Central, which will allow us to sell purity ethane and purity propane through separate pipelines and purity iso-butane and purity normal butane through truck racks, helping to offset the effect of fractionation capacity constraints on our NGL revenue. We anticipate completing this project in early 2010.

Credit and Capital Market Disruptions. The effects of late-2008 disruptions in financial markets worldwide continue to influence the availability of debt and equity capital, although to a lesser degree. Generally, we believe that the markets have recovered significantly since the height of the financial crisis, although the cost of capital remains higher than before the financial crisis. To the extent we access financial markets in the near term, we believe that we would be able to raise debt and equity on acceptable terms, although the cost of either would depend on then-existing market conditions.

Renewed instability in the financial markets, as a result of developments in the recent recession or otherwise, would have a negative impact on the cost and accessibility of capital for us, and for our customers and suppliers.

Factors Affecting Operating Results and Financial Condition

Our results for the three and nine months ended September 30, 2009 reflect the lower prices and modestly lower volumes we encountered during these periods compared to the high commodity prices and increasing

volumes that prevailed during the same periods in 2008. A comparison of the second and third quarters of 2009, however, reveals the continuing benefits of strengthening NGL prices. Higher NGL prices overall combined with lower natural gas prices in Texas during the third quarter of 2009 have led to improvement in our processing margins compared to the second quarter. This improvement was offset in part by lower NGL revenue due to fractionation capacity constraints. In addition, while our overall volumes were lower, the volume of natural gas that we processed increased slightly compared to the second quarter. As a result of the increased margins and volumes for processed gas, our combined operating segment gross margins increased 7% compared to the second quarter of 2009.

Consistent with our business strategy, we have used derivative instruments to mitigate the effects of commodity price fluctuations on our cash flow and profitability so that we can continue to meet our debt service and capital expenditure requirements, and our distribution objectives. For the three and nine months ended September 30, 2009, we received $16.4 million and $62.3 million, respectively, in cash settlements from our commodity hedge portfolio, which helped to offset the decline in operating revenues attributable to lower commodity prices. The basis spread between Mt. Belvieu and Conway limited the benefit we received from our NGL hedging portfolio because we hedge Oklahoma NGL volume with hedge instruments based on Mt. Belvieu prices. For the three and nine months ended September 30, 2008, we paid $7.0 million and $19.4 million, respectively, in cash settlements to satisfy commodity swap obligations. Our results also reflect lower general and administrative and operating expenses due to our continuing cost control efforts.

How We Evaluate Our Operations

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

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

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

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

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

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

In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered using our firm capacity gathering agreements with Fort Union and volumes transported using our firm transportation agreements with WIC, 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 and NGLs we purchase, cost of crude oil we purchase and costs for transportation of our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to more easily identify operational or other issues within a segment. With respect to our 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, consist of fixed-fee arrangements providing for an agreed gathering fee per unit of natural gas throughput. Our revenues from these arrangements are directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent 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 contract portfolio, we use total segment gross margin, which is the sum of our operating segments' gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities. The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii) amortization expense relating to the option component of our commodity derivative instruments and
(iii) unrealized mark-to-market gain or loss on our commodity derivative instruments that have not been designated as cash flow hedges.

Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for 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 8 of the notes to the unaudited consolidated 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. See Note 8 of the notes to the unaudited consolidated 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 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, amortization and impairment expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and Southern Dome), our management also . . .