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

Forward-Looking Statements

This report contains "forward-looking statements" within the meaning of the federal securities laws. All statements in this report other than statements of historical fact, including those under "- Trends and Uncertainties," "- Our Results of Operations" and "- Liquidity and Capital Resources" are forward-looking statements. Forward-looking statements address activities, events or developments that we expect or anticipate will or may occur in the future, including references to future goals or intentions. These statements can be identified by the use of forward-looking terminology, including "may," "believe," "expect," "anticipate," "estimate," "continue," or similar words. These statements include assertions related to plans for growth of our business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed or implied in these statements. Any differences could be caused by a number of factors, including, but not limited to:

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

º •
º our ability to continue to connect new sources of natural gas, crude oil and condensate, and the NGL content of new gas supplies;

º •
º the ability of key producers to continue to drill and successfully complete and connect new natural gas and condensate volumes and such producers' performance under their contracts with us;

º •
º our ability to attract and retain key customers and contract with new customers, and such customers' performance under their contracts with us;

º •
º our ability to access or construct new pipeline capacity, gas processing and NGL fractionation and transportation capacity;

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

º •
º our ability (and the ability of our third-party service providers) to meet in-service dates, cost expectations and operating performance standards for construction projects;

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

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

º •
º the effectiveness of our hedging program;

º •
º general economic conditions;

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

º •
º the effects of government regulations and policies;

º •
º our ability to complete the proposed merger with Kinder Morgan; and

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

This report includes cautionary statements identifying important factors that could cause our actual results to differ materially from our expectations expressed or implied in forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this report. All forward-looking statements in this report and all subsequent written or oral forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements. Forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

Overview

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

º •
º Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation and, through August 2012, included our Lake Charles processing plant located in southwest Louisiana. In addition to our 100%-owned operations, this segment includes our equity investments in Webb Duval, Eagle Ford Gathering, Liberty Pipeline Group and Double Eagle Pipeline.

º •
º Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including primarily low-pressure gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome.

º •
º Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. In addition to our 100%-owned producer services business, this segment includes our equity investments in Bighorn and Fort Union.

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

Proposed Merger with Kinder Morgan. On January 29, 2013, we announced a definitive merger agreement with Kinder Morgan, under which Kinder Morgan will acquire all of Copano's outstanding equity in a unit-for-unit transaction with an exchange ratio of 0.4563 Kinder Morgan units per Copano unit. The transaction is valued at approximately $5 billion (including the assumption of debt) based on the closing price for Kinder Morgan's units on January 29, 2013. Our board of directors and Kinder Morgan's board of directors have approved the merger agreement, and we have agreed to submit the merger agreement to a vote of our unitholders and to recommend that unitholders approve the merger agreement. TPG, our largest unitholder (owning over 14% of our outstanding equity), has agreed to vote all of its

Series A convertible preferred units (and common units, if any) in favor of adoption of the merger agreement.

At the effective time of the merger, each of our common units outstanding or deemed outstanding as of immediately prior to the effective time will be converted into the right to receive 0.4563 Kinder Morgan common units (the "Merger Consideration"). All grants then outstanding under our LTIP will vest, outstanding options and unit appreciation rights will be deemed net exercised, and all resulting common units will convert into the right to receive the Merger Consideration. The merger agreement includes customary representations, warranties and covenants, and specific agreements relating to the conduct of our business and Kinder Morgan's business between the date of the signing of the merger agreement and the closing of the merger, and the efforts of the parties to cause the merger transactions to be completed. In addition to certain other covenants, we have agreed not to encourage, solicit, initiate or facilitate any takeover proposal from a third party or enter into any agreement, arrangement or understanding requiring us to abandon, terminate or fail to consummate the merger and related transactions.

Completion of the merger is subject to satisfaction or waiver of certain closing conditions including, among others, customary regulatory approvals (including under the Hart-Scott Rodino Antitrust Improvements Act of 1976, as amended), approval by our unitholders and registration of the Merger Consideration under the securities laws. The merger agreement contains certain termination rights for both us and Kinder Morgan and further provides that, upon termination of the merger agreement, under certain circumstances, we may be required to pay Kinder Morgan a termination fee equal to $115 million, and under certain other circumstances, Kinder Morgan may be required to pay us a termination fee equal to $75 million.

Under the terms of the merger agreement, we have agreed to conduct our business in the ordinary course and in all material respects in substantially the same manner as conducted prior to the date of the merger agreement, subject to certain conditions and restrictions including, but not limited to, restrictions on our ability to (i) commit to new capital expenditures,
(ii) acquire, invest in, or dispose of any material properties, assets, or equity interests as defined in the merger agreement, (iii) incur new debt, refinance, or guarantee debt or borrowed money, (iv) enter into, terminate, or amend certain material contracts and (v) issue, grant, sell, or redeem our common units or pay distributions in excess of $0.575 per common unit.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business and many of the factors affecting our business are beyond our control and are difficult to predict.

Our gross margins and total distributable cash flow are affected by commodity prices and by the volumes of natural gas, NGLs and condensate that flow through our assets. Generally, commodity prices affect the cash flow and profitability of our Texas and Oklahoma segments directly because some of our contracts in those segments have commodity-sensitive pricing terms. In addition, commodity prices affect all of our segments indirectly because they influence exploration and production activity, which underlies the demand for our services and the long-term growth and sustainability of our business.

Commodity prices are influenced by various factors that affect supply and demand. These factors include regional drilling activity and completion technology, natural gas, NGL and crude oil storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and the availability, proximity and capacity of downstream infrastructure and markets for natural gas, condensate and NGLs. Many of the factors affecting demand are in turn dependent on overall economic activity. For example, demand for ethane, a primary feedstock for petrochemical and manufacturing industries, varies depending on overall economic activity. Factors that can cause volatility in crude oil prices, such as international political and economic events, can also affect NGL and condensate prices because the two have historically

been correlated. Also, demand for natural gas used in power generation varies depending on the relative prices for natural gas and coal.

Producers typically increase drilling and well completions when prices are sufficient to make these activities economic, and they may reduce or suspend these activities when they have become uneconomic. The point at which producer activity becomes economic depends on a combination of factors in addition to commodity prices. In many cases, producers of rich gas can benefit from NGL prices under their contracts; for these producers, strong NGL prices may offset the potential disincentive of weak natural gas prices. Strong crude oil prices may also support increased production of casinghead natural gas associated with crude oil production.

Other factors that affect a producer's ability and incentives to drill include the producer's operating costs and financial resources (both access to capital and cost of capital), the availability of labor and necessary equipment and services, the expected composition of wellhead production and the availability, proximity and capacity of downstream infrastructure, services and market outlets. Also, some producers rely on commodity price hedging to support drilling activity when prices are less favorable, and some may drill only to the extent necessary to maintain their leasehold interests or capital commitments, either of which may require drilling within a specified period of time.

The impact of changes in drilling and well completion activity on our throughput volumes may be gradual because of the time required to complete and connect new wells (or at times when drilling is declining, because of continuing production from existing wells). Delays can range from a few days, in areas with minimal time required to complete and connect wells, to as long as 18 months, if extensive dewatering or completion of downstream facilities is required.

Some of our producer contracts entitle us to deficiency fees, which help to mitigate the impact of lower drilling and production activity. However, we may be subject to increased credit risk over periods when a producer is making payments to us that are not supported by physical volumes. In addition, our cash flow will be affected because in most cases deficiency fees are not paid monthly; rather, they become payable after the end of a longer commitment period, such as annually. Furthermore, deficiency fees may be less than the amount we would receive if the producer had delivered physical volumes. In the case of deficiency fees payable to one of our unconsolidated affiliates, the payment is reflected in our cash flow only after the unconsolidated affiliate has made a cash distribution to us, which may occur in a subsequent quarter or year.

Fourth-Quarter 2012 Commodity Prices Overall. Natural gas prices continued to improve in the fourth quarter of 2012 after reaching 10-year-lows in the second quarter, but declined in January and February of 2013. Average NYMEX crude oil prices decreased from the third quarter of 2012 to $88.18 per Bbl for the fourth quarter, and the spot price at February 20, 2013 was $92.84 per Bbl. Weighted-average NGL prices at Mont Belvieu for the fourth quarter of 2012 were $37.43, down slightly from $37.52 for the third quarter, while Conway prices for the fourth quarter averaged $36.12 per Bbl, up from $31.44 per Bbl for the third quarter. Fourth-quarter average ethane prices at Conway increased to $7.72 per Bbl, compared to $6.07 per Bbl for the third quarter, while Mont Belvieu ethane prices declined, averaging $11.92 per Bbl compared to $14.22 per Bbl for the third quarter. The weighted-average spread between Mont Belvieu and Conway narrowed to $3.12 per Bbl over the fourth quarter, down from $7.15 per Bbl for the third quarter, due mainly to the decline in Mont Belvieu ethane prices coupled with overall improvement in Conway prices. The spread was $1.53 per Bbl on February 20, 2013.

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

                      Annual Data for Texas                       Quarterly Data for Texas
                  2010        2011        2012           Q1 2012     Q2 2012     Q3 2012     Q4 2012
Houston Ship
Channel
($/MMBtu)       $    4.38   $    4.02   $    2.75       $    2.65   $    2.17   $    2.84   $    3.35
Mont Belvieu
($/Bbl)         $   44.68   $   56.96   $   40.28       $   52.64   $   38.71   $   37.52   $   37.43
NYMEX crude
oil ($/Bbl)     $   79.53   $   95.12   $   94.20       $  102.93   $   93.49   $   92.22   $   88.18
100% owned
Service
throughput
(MMBtu/d)         595,641     726,944     895,212         944,033     924,465     897,601     814,684
Plant inlet
(MMBtu/d)         504,810     639,194     811,813         833,163     834,846     824,196     755,395
NGLs produced
(Bbls/d)           18,718      28,736      48,802          35,344      50,146      54,142      56,434
Segment gross
margin (in
thousands)      $ 128,682   $ 184,437   $ 204,324       $  45,341   $  49,101   $  55,236   $  54,646
Joint
Venture(1)
Pipeline
throughput
(Mmbtu/d)          54,879     162,734     353,697         269,433     316,111     373,402     454,862
NGLs produced
(Bbls/d)(2)             -       1,698      12,528           9,912      10,169      12,526      17,450
Gross margin
(in
thousands)      $   1,698   $  31,195   $  93,725       $   9,815   $  26,964   $  25,945   $  31,001


--------------------------------------------------------------------------------
   º (1)

º (2)
º Net of NGLs produced at our Houston Central complex.

The first-of-the-month price for natural gas on the Houston Ship Channel index for February 2013 was $3.23 per MMBtu, and the spot price on February 20, 2013 was $3.22 per MMBtu. The weighted-average spot price for NGLs at Mont Belvieu on February 20, 2013, based on our fourth-quarter 2012 product mix, was $39.31 per Bbl.

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

                    Annual Data for Oklahoma                     Quarterly Data for Oklahoma
                  2010        2011        2012           Q1 2012     Q2 2012     Q3 2012     Q4 2012
CenterPoint
East
($/MMBtu)       $    4.19   $    3.87   $    2.67       $    2.60   $    2.11   $    2.72   $    3.24
Conway
($/Bbl)         $   40.21   $   47.32   $   34.27       $   39.18   $   30.23   $   31.44   $   36.12
NYMEX crude
oil ($/Bbl)     $   79.53   $   95.12   $   94.20       $  102.93   $   93.49   $   92.22   $   88.18
100% owned
Service
throughput
(MMBtu/d)         261,636     287,408     315,029         318,285     324,915     313,414     303,645
Plant inlet
(MMBtu/d)         156,181     155,675     158,754         157,052     158,106     157,775     162,057
NGLs produced
(Bbls/d)           16,251      17,498      16,644          16,691      17,028      16,207      16,390
Segment gross
margin (in
thousands)      $  93,617   $ 105,080   $  88,468       $  24,199   $  20,171   $  22,948   $  21,150
Joint
Venture(1)
Plant inlet
(MMBtu/d)          12,522      11,292       9,961          10,017       7,352      10,354      12,095
NGLs produced
(Bbls/d)              449         403         351             363         249         375         417
Gross margin
(in
thousands)      $   5,654   $   5,096   $   3,418       $   1,003   $     491   $     848   $   1,076


--------------------------------------------------------------------------------
   º (1)

The first-of-the-month price for natural gas on the CenterPoint East index for February 2013 was $3.16 per MMBtu, and the spot price on February 20, 2013 was $3.21 per MMBtu. The weighted-average spot price for NGLs at Conway on February 20, 2013, based on our fourth-quarter 2012 product mix, was $37.77 per Bbl.

Basis Trends. Basis risk continues to affect our hedges relating to Oklahoma NGL volumes, but we benefited from a narrowing of the Mont Belvieu-Conway basis spread in the fourth quarter of 2012. We use Mont Belvieu-priced hedge instruments for our Oklahoma NGL volumes because the forward market for Conway-based hedge instruments is limited.

The weighted-average Mont Belvieu-Conway basis differential at February 20, 2013, based on our fourth-quarter 2012 product mix, was $1.53 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices for the fourth quarter of 2012 was $(0.11) per MMBtu.

The following graph summarizes the basis differential between Mont Belvieu and Conway prices.

Pricing Trends in the Rocky Mountains. The following graph and table summarize prices for natural gas on Colorado Interstate Gas, the primary index we use for the Rocky Mountains.

                Annual Data for Rocky Mountains                Quarterly Data for Rocky Mountains
                 2010           2011        2012           Q1 2012     Q2 2012     Q3 2012     Q4 2012
Colorado
Interstate
Gas
($/MMBtu)     $      3.92     $    3.79   $    2.58       $    2.62   $    1.95   $    2.55   $    3.20
100% owned
Segment
gross
margin (in
thousands)    $     4,440     $   2,641   $     932       $     358   $     187   $     624   $    (237 )
Joint
Venture(1)
Pipeline
throughput
(MMBtu/d)         907,809       604,261     726,026         787,366     747,009     694,961     675,662
Gross
margin (in
thousands)    $    89,888     $  85,751   $  83,670       $  21,462   $  18,741   $  18,035   $  25,432


--------------------------------------------------------------------------------
   º (1)

The first-of-the-month price for natural gas on the Colorado Interstate Gas index for February 2013 was $3.17 per MMBtu, and the spot price on February 20, 2013 was $3.34 per MMBtu.

Other Industry Trends. Volume growth from rich gas shale plays such as the Eagle Ford Shale continues to stress existing processing and liquids-handling infrastructure. NGL transportation and fractionation facilities remain subject to capacity constraints and older processing facilities are subject to reduced operating performance due to the very high NGL content of gas from these plays.

Transportation costs for crude oil, condensate and heavier NGL products in Texas remain higher due to limited pipeline infrastructure and available trucking capacity. In addition, we believe that limited fractionation capacity at Mont Belvieu and a lack of available NGL pipeline capacity in the Mid-Continent contributed to a wide basis spread between Mont Belvieu and Conway for much of 2012. We anticipate that new pipeline infrastructure linking the Mid-Continent and Gulf Coast regions, which is scheduled to come online in 2013 and 2014, will help to reduce volatility in this basis spread. Initially, this new pipeline infrastructure may result in downward pressure on Mont Belvieu prices due to insufficient petrochemical cracking capacity along the Gulf Coast. New capacity is expected to begin coming on line in 2016 or 2017.

Generally, processing and NGL capacity constraints result in higher processing fees and NGL transportation and fractionation costs for parties that do not have contractually fixed costs. Midstream companies experiencing capacity constraints or related outages may curtail volumes, experience reduced operating performance or, where possible, reject ethane, each of which can have an immediate impact on cash flow and operating results for both the midstream company and its producers and other customers. While these effects could limit the benefits producers receive from rich gas production and therefore affect the level of producer activity, we anticipate that the impact of processing and fractionation capacity constraints may begin to improve as new facilities come online in 2014.

º •
º Drilling. Drilling activity remained steady in the Eagle Ford Shale and north Barnett Shale Combo plays in Texas and the Hunton de-watering play in Oklahoma. Drilling activity in the leaner areas of the Woodford Shale behind our Mountains system in Oklahoma remained suspended in the fourth quarter due to low natural gas prices, while activity in the richer areas of the Woodford Shale continues. Drilling activity in the rich Mississippi Lime area in northern Oklahoma and southern Kansas has increased as producers further explore the play. In the Rocky Mountains and in other areas of Texas and Oklahoma, drilling activity has remained very low.

º •
º Volumes. Our overall service throughput volumes for the fourth quarter of 2012 decreased 3% compared to the third quarter of 2012 and increased 6% compared to the fourth quarter of 2011.

. . .