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Copano Energy Reports Third Quarter 2011 Results

November 3, 2011

HOUSTON, Nov. 3, 2011 /PRNewswire/ — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three and nine months ended September 30, 2011.

“We are pleased with our third quarter results as our operating segment gross margin continues to benefit from growing volumes in the Eagle Ford Shale and the north Barnett Shale Combo areas and a strong NGL pricing environment,” said R. Bruce Northcutt, Copano Energy’s President and Chief Executive Officer.

“We are making significant progress on our Eagle Ford Shale strategy as we complete and integrate the bulk of our 2011 projects, several of which have begun accepting volumes on a limited basis.

“We continue to see strong producer activity in the Eagle Ford Shale and when these projects are placed into full-service, they will have an immediate and positive impact on our distributable cash flow and distribution coverage,” Northcutt added.

Third Quarter Financial Results

Total distributable cash flow for the third quarter of 2011 increased 3% to $36.9 million from $35.7 million for the third quarter of 2010 and decreased 2% from $37.6 million in the second quarter of 2011. Third quarter 2011 total distributable cash flow represents 95% coverage of the third quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.

Revenue for the third quarter of 2011 increased 49% to $353.7 million compared to $237.7 million for the third quarter of 2010 and increased 2% compared to $346.1 million in the second quarter of 2011. Operating segment gross margin increased 32% to $72.8 million compared to $55.3 million for the third quarter of 2010 and decreased 4% compared to $75.6 million in the second quarter of 2011. Total segment gross margin increased 12% to $64.8 million for the third quarter of 2011 compared to $57.9 million for the third quarter of 2010 and decreased 1% compared to $65.3 million for the second quarter of 2011.

Adjusted EBITDA for the third quarter of 2011 was $51.8 million compared to $51.0 million for the third quarter of 2010 and $54.4 million for the second quarter of 2011.

Net loss was $157.7 million for the third quarter of 2011 compared to net income of $7.3 million for the third quarter of 2010. Net loss for the third quarter of 2011 includes a $170 million non-cash impairment charge relating to the Company’s assets in the Rocky Mountains primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and drilling activity in Wyoming’s Powder River Basin.

Net loss to common units after deducting $8.3 million of in-kind preferred unit distributions totaled $166.0 million, or $2.51 per unit on a diluted basis, for the third quarter of 2011 compared to net loss to common units of $0.2 million, or less than $0.01 per unit on a diluted basis, for the third quarter of 2010. Weighted average diluted units outstanding totaled 66.2 million for the third quarter of 2011 as compared to 65.7 million for the same period in 2010. Excluding the impact of the non-cash impairment charge, adjusted net income to common units totaled $4.0 million, or approximately $0.06 per unit on a diluted basis, for the third quarter of 2011.

Total distributable cash flow, total segment gross margin, adjusted EBITDA, segment gross margin and adjusted net income are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this press release. Commencing with the second quarter of 2011, Copano revised its method for calculating adjusted EBITDA and its presentation of total distributable cash flow. For a detailed discussion of these changes, please read “Use of Non-GAAP Financial Measures” beginning on page 7 of this news release.

Third Quarter Operating Results by Segment

Copano manages its business in three geographical operating segments: Texas, which provides midstream natural gas services in north and south Texas and also includes a processing plant in southwest Louisiana; Oklahoma, which provides midstream natural gas services in central and east Oklahoma; and the Rocky Mountains, which provides midstream natural gas services to producers in Wyoming’s Powder River Basin and includes managing member interests in Bighorn Gas Gathering, L.L.C. (Bighorn) of 51% and in Fort Union Gas Gathering, L.L.C. (Fort Union) of 37.04%.

Texas

Segment gross margin for Texas increased 43% to $44.5 million for the third quarter of 2011 compared to $31.2 million for the third quarter of 2010 and decreased 3% from $46.1 million for the second quarter of 2011. The year-over-year increase resulted primarily from (i) a 9% increase in realized margins on service throughput compared to the third quarter of 2010 ($0.63 per MMBtu in 2011 compared to $0.58 per MMBtu in 2010) reflecting higher NGL prices and (ii) an increase in pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays. During the third quarter of 2011, throughput volumes for the Eagle Ford Shale and the north Barnett Shale Combo plays increased 25% and 41%, respectively, from the second quarter of 2011. During the third quarter of 2011, weighted-average NGL prices on the Mont Belvieu index, based on Copano’s product mix for the period, were $59.43 per barrel compared to $40.16 per barrel during the third quarter of 2010, an increase of 48%. During the third quarter of 2011, natural gas prices on the Houston Ship Channel index averaged $4.23 per MMBtu compared to $4.33 per MMBtu during the third quarter of 2010, a decrease of 2%.

During the third quarter of 2011, the Texas segment provided gathering, transportation and processing services for an average of 765,744 MMBtu/d of natural gas compared to 590,116 MMBtu/d for the third quarter of 2010, an increase of 30%. The Texas segment gathered an average of 463,321 MMBtu/d of natural gas during the third quarter of 2011, an increase of 45% over last year’s third quarter, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. Processed volumes increased 33% to an average of 686,398 MMBtu/d of natural gas at Copano’s plants and third-party plants. NGL production increased 57% to an average of 30,904 Bbls/d at Copano’s plants and third-party plants, reflecting increased volumes behind Copano’s Houston Central complex in south Texas and the Saint Jo plant in the north Barnett Shale Combo play in north Texas.

The decrease in segment gross margin from the second quarter of 2011 was a result of the curtailment of volumes at the Houston Central complex because a scheduled turnaround at the Point Comfort facility caused a downstream market constraint, the scheduled maintenance on the Company’s purity propane line, and a decrease in volumes under a short-term and interruptible contract on the DK pipeline offset by increased Eagle Ford Shale volumes.

Oklahoma

Segment gross margin for Oklahoma increased 21% to $27.9 million for the third quarter of 2011 compared to $23.0 million for the third quarter of 2010 and decreased 3% from $28.7 million for the second quarter of 2011. The year-over-year increase resulted primarily from (i) a 13% increase in realized margins on service throughput compared to the third quarter of 2010 ($1.05 per MMBtu in 2011 compared to $0.93 per MMBtu in 2010), primarily reflecting higher NGL prices, (ii) the acquisition of the Harrah plant on April 1, 2011 and (iii) an increase in service throughput attributable to volume growth from the Woodford Shale. During the third quarter of 2011, weighted-average NGL prices on the Conway index, based on Copano’s product mix for the period, were $49.21 per barrel compared to $36.53 per barrel during the third quarter of 2010, an increase of 35%. During the third quarter of 2011, natural gas prices on the CenterPoint East index averaged $4.05 per MMBtu compared to $4.14 per MMBtu during the third quarter of 2010, a decrease of 2%.

The Oklahoma segment gathered an average of 288,440 MMBtu/d of natural gas, processed an average of 158,070 MMBtu/d of natural gas and produced an average of 17,453 Bbls/d of NGLs at its own plants and third-party plants during the third quarter of 2011. Compared to the third quarter of 2010, this represents a 7% increase in service throughput, a 1% increase in plant inlet volumes and a 6% increase in NGL production. The increase in service throughput is primarily attributable to increased drilling and production of lean gas in the Woodford Shale area near Copano’s Cyclone Mountain system, offset by normal production declines in rich gas areas.

The decrease in segment gross margin from the second quarter of 2011 was primarily related to a drop in natural gas and NGL prices.

Rocky Mountains

Segment gross margin for the Rocky Mountains segment totaled $0.4 million in the third quarter of 2011 compared to $1.1 million for the third quarter of 2010 and $0.8 million for the second quarter of 2011. The Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano’s interests in Bighorn and Fort Union, which are accounted for under the equity method of accounting and are shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.” Average pipeline throughput for Bighorn and Fort Union on a combined basis decreased 27% to 670,543 MMBtu/d in the third quarter of 2011 as compared to 913,730 MMBtu/d in the third quarter of 2010. The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada’s Bison Pipeline upon its start up in January 2011. Fort Union volumes do not reflect 223,557 MMBtu/d in long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union for the three months ended September 30, 2011.

Corporate and Other

Corporate and other segment gross margin includes Copano’s commodity risk management activities. These activities contributed a loss of $8.0 million for the third quarter of 2011 compared to income of $2.6 million for the third quarter of 2010 and a loss of $10.3 million for the second quarter of 2011. The loss for the third quarter of 2011 included $7.4 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $2.9 million of net cash settlements paid for expired commodity derivative instruments offset by $2.3 million of unrealized gains on undesignated economic hedges. The third quarter 2010 gain included $11.1 million of net cash settlements received for expired commodity derivative instruments offset by $8.2 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $0.3 million of unrealized mark-to-market losses on undesignated economic hedges.

Year to Date Financial Results

Revenue for the nine months ended September 30, 2011 increased 35% to $989.7 million compared to $734.4 million for the same period in 2010. Operating segment gross margin increased 34% to $217.6 million compared to $162.6 million for the nine months ended September 30, 2010. Total segment gross margin increased 15% to $190.5 million for the nine months ended September 30, 2011 compared to $165.9 million for the same period in 2010.

Adjusted EBITDA for the nine months ended September 30, 2011 was $153.6 million compared to $146.3 million for the same period in 2010.

Net loss was $163.6 million for the nine months ended September 30, 2011 compared to net loss of $15.1 million for the same period in 2010. Net loss for the first nine months of 2011 includes a loss on the refinancing of unsecured debt of $18.2 million and a $170.0 million non-cash impairment charge relating to our Rocky Mountains assets discussed above. Net loss for the first nine months of 2010 includes a $25 million non-cash impairment charge relating to the Company’s investment in Bighorn.

Net loss to common units after deducting $24.2 million of in-kind preferred unit distributions beginning in July 2010 totaled $187.8 million, or $2.84 per unit on a diluted basis, for the nine months ended September 30, 2011 compared to net loss to common units of $22.6 million, or $0.36 per unit on a diluted basis, for the same period in 2010. Weighted average diluted units outstanding totaled 66.1 million for the nine months ended September 30, 2011 as compared to 63.2 million for the same period in 2010.

Cash Distributions

On October 12, 2011, Copano announced its third quarter 2011 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units. This distribution is unchanged from the second quarter of 2011 and will be paid on November 10, 2011 to common unitholders of record at the close of business on October 31, 2011.

Conference Call Information

Copano will hold a conference call to discuss its third quarter 2011 financial results on November 4, 2011 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9818 and ask for the Copano call 10 minutes prior to the start time, or access it live over the internet at www.copanoenergy.com on the “Investor Overview” page of the “Investor Relations” section of Copano’s website.

A replay of the audio webcast will be available shortly after the call on Copano’s website. A telephonic replay will be available through November 11, 2011 by calling (303) 590-3030 and using the pass code 4476344#.

Use of Non-GAAP Financial Measures

This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano’s non-GAAP financial measures may not be comparable to similarly titled measures of other companies, which may not calculate their measures in the same manner.

Copano’s management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets. Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the same financial measures that its management uses in evaluating its performance.

Adjusted EBITDA. Commencing with the second quarter of 2011, Copano revised its calculation of adjusted EBITDA to more closely resemble that of many of Copano’s peers in terms of measuring the company’s ability to generate cash. Adjusted EBITDA (as revised) equals:

  • net income (loss);
  • plus interest and other financing costs, provision for income taxes, depreciation, amortization and impairment expense, non-cash amortization expense associated with commodity derivative instruments, distributions from unconsolidated affiliates, loss on refinancing of unsecured debt and equity-based compensation expense;
  • minus equity in earnings (loss) from unconsolidated affiliates and unrealized gains (losses) from commodity risk management activities; and
  • plus or minus other miscellaneous non-cash amounts affecting net income (loss) for the period.

In calculating adjusted EBITDA as revised, Copano no longer adds to EBITDA (earnings before interest, taxes, depreciation and amortization) its share of the depreciation, amortization and impairment expense and interest and other financing costs embedded in equity in earnings (loss) from unconsolidated affiliates; instead, Copano now adds to EBITDA (i) other non-cash amounts affecting net income (loss) for the period, (ii) non-cash amortization expense associated with commodity derivative instruments, (iii) loss on refinancing of unsecured debt and (iv) distributions from unconsolidated affiliates.

Copano believes that the revised calculation of adjusted EBITDA is a more effective tool for its management in evaluating operating performance for several reasons. Although Copano’s historical method for calculating adjusted EBITDA was useful in assessing the performance of Copano’s assets (including its unconsolidated affiliates) without regard to financing methods, capital structure or historical cost basis, the prior calculation was not as useful in evaluating the core performance of its assets and their ability to generate cash because adjustments for a number of non-cash expenses and other non-cash and non-operating items were not reflected in the calculation, and the impact of cash distributions from unconsolidated affiliates was likewise not reflected. Additionally, Copano believes that the revised calculation of adjusted EBITDA is more consistent with the method and presentation used by many of its peers and will allow management to better evaluate the company’s performance relative to its peer companies.

Also, Copano believes that the revised calculation more effectively represents what lenders and debt holders, as well as industry analysts and many of its unitholders, have indicated is useful in assessing Copano’s core performance and outlook and comparing Copano to other companies in its industry. For example, Copano believes that adjusted EBITDA as revised may provide investors and analysts with a more useful tool for evaluating the company’s leverage because it more closely resembles Consolidated EBITDA (as defined under Copano’s revolving credit facility), which is used by lenders to calculate financial covenants. Consolidated EBITDA differs from adjusted EBITDA in that it includes further adjustments to (i) reflect the pro forma effects of material acquisitions and dispositions and (ii) in the case of leverage ratio calculations, includes projected EBITDA from significant capital projects under construction.

Total Distributable Cash Flow. Commencing with the second quarter of 2011, Copano presents total distributable cash flow as net income (loss) plus all adjustments included in the adjusted EBITDA calculation described above and minus: (i) interest expense, (ii) current tax expense and (iii) maintenance capital expenditures. Although Copano has revised its presentation of total distributable cash flow, the components of the calculation have not changed, except that total distributable cash flow now eliminates the impact of any loss on refinancing of unsecured debt because such losses do not reduce operating cash flow.

Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana. Its assets include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 340 miles of NGL pipelines and ten natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 barrels per day of fractionation capacity. For more information, please visit www.copanoenergy.com.

This press release includes “forward-looking statements,” as defined by the Securities and Exchange Commission. Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements. These statements include, but are not limited to, statements about future producer activity and Copano’s total distributable cash flow and distribution coverage. These statements are based on management’s experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation, the following risks and uncertainties, many of which are beyond Copano’s control: The volatility of prices and market demand for natural gas and NGLs; Copano’s ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production and producers’ ability to drill and successfully complete and attach new natural gas supplies and the availability of downstream transportation systems and other facilities for natural gas and NGLs; higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; 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 Copano’s filings with the Securities and Exchange Commission.

- financial statements to follow -


    Contacts:      Carl Luna, SVP & CFO
                   Copano Energy, L.L.C.
                   713-621-9547

                   Jack Lascar / jlascar@drg-l.com
                   Anne Pearson / apearson@drg-l.com
                   DRG&L / 713-529-6600


                                   COPANO ENERGY, L.L.C. AND SUBSIDIARIES
                               UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

                                                 Three Months Ended                  Nine Months Ended
                                                 ------------------                  -----------------
                                                   September 30,                       September 30,
                                                   -------------                       -------------

                                                    2011                2010                  2011         2010
                                                    ----                ----                  ----         ----

                                                           (In thousands, except per unit
                                                                    information)
    Revenue:
      Natural gas sales                         $120,815             $87,524              $348,538     $292,559
      Natural gas liquids
       sales                                     191,370             118,999               521,129      353,119
      Transportation,
       compression and
       processing fees                            30,337              17,909                82,706       47,539
      Condensate and other                        11,169              13,272                37,299       41,204
        Total revenue                            353,691             237,704               989,672      734,421

    Costs and expenses:
      Cost of natural gas
       and natural gas
       liquids(1)                                281,858             174,461               779,986      551,939
      Transportation (1)                           6,991               5,340                19,202       16,619
      Operations and
       maintenance                                16,091              13,004                46,953       38,337
      Depreciation,
       amortization and
       impairment                                 21,911              15,218                56,143       46,002
      General and
       administrative                             10,031               9,869                34,530       31,311
      Taxes other than
       income                                      1,502               1,315                 4,029        3,658
      Equity in loss
       (earnings) from
       unconsolidated
       affiliates                                161,589              (2,049)              158,581       19,788
        Total costs and
         expenses                                499,973             217,158             1,099,424      707,654

    Operating (loss)
     income                                     (146,282)             20,546              (109,752)      26,767
    Other income
     (expense):
      Interest and other
       income                                         16                  15                    31           59
      Loss on refinancing of
       unsecured debt                                  -                   -               (18,233)           -
      Interest and other
       financing costs                           (11,080)            (12,943)              (34,450)     (41,239)
    (Loss) income before
     income taxes                               (157,346)              7,618              (162,404)     (14,413)
    Provision for income
     taxes                                          (390)               (320)               (1,161)        (660)
                                                    ----                ----                ------         ----
    Net (loss) income                           (157,736)              7,298              (163,565)     (15,073)
    Preferred unit
     distributions                                (8,279)             (7,500)              (24,235)      (7,500)
                                                  ------              ------               -------       ------
    Net loss to common
     units                                     $(166,015)              $(202)            $(187,800)    $(22,573)
                                               =========               =====             =========     ========

    Basic and diluted net
     loss per common unit                         $(2.51)       $          -                $(2.84)      $(0.36)
                                                              ===        ===                             ======
    Weighted average
     number of common
     units                                        66,246              65,658                66,125       63,193
                                                  ======              ======                ======       ======

    Distributions declared
     per common unit                              $0.575              $0.575                $1.725       $1.725
                                                  ======              ======                ======       ======

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


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

                                                                     Nine Months Ended
                                                                       September 30,
                                                                    ------------------
                                                                      2011                 2010
                                                                      ----                 ----
    Cash Flows From Operating
     Activities:                                                        (In thousands)
      Net loss                                                   $(163,565)            $(15,073)
      Adjustments to reconcile net
       loss to net cash provided
       by operating activities:
        Depreciation, amortization
         and impairment                                             56,143               46,002
        Amortization of debt issue
         costs                                                       2,855                2,773
        Equity in loss from
         unconsolidated affiliates                                 158,581               19,788
        Distributions from
         unconsolidated affiliates                                  17,961               16,999
        Loss on refinancing of
         unsecured debt                                             18,233                    -
        Non-cash gain on risk
         management activities, net                                 (4,723)                (555)
        Equity-based compensation                                    7,445                7,118
        Deferred tax provision                                         253                  (19)
        Other non-cash items                                           (86)                (458)
        Changes in assets and
         liabilities, net of
         acquisitions:
          Accounts receivable                                      (11,132)              10,586
          Prepayments and other
           current assets                                           (2,952)               2,135
          Risk management activities                                11,353               10,766
          Accounts payable                                          17,459               (6,518)
          Other current liabilities                                 14,964                  945
                                                                    ------                  ---
            Net cash provided by
             operating activities                                  122,789               94,489
                                                                   -------               ------

    Cash Flows From Investing
     Activities:
      Additions to property, plant
       and equipment                                              (175,323)            (101,265)
      Additions to intangible
       assets                                                       (5,316)              (2,259)
      Acquisitions                                                 (16,084)                   -
      Investments in
       unconsolidated affiliates                                  (105,111)             (11,186)
      Distributions from
       unconsolidated affiliates                                     2,368                2,555
      Escrow cash                                                        6                    -
      Proceeds from sale of assets                                     248                  279
      Other                                                             98                  280
                                                                       ---                  ---
            Net cash used in investing
             activities                                           (299,114)            (111,596)
                                                                  --------             --------

    Cash Flows From Financing
     Activities:
      Proceeds from long-term
       debt                                                        725,000               80,000
      Repayment of long-term debt                                 (412,665)            (350,000)
      Payments of premiums and
       expenses on redemption of
       unsecured debt                                              (14,572)                   -
      Deferred financing costs                                     (15,743)                (995)
      Distributions to unitholders                                (114,834)            (107,612)
      Proceeds from issuance of
       Series A convertible
       preferred units, net of
       underwriting
        discounts and commissions of
         $8,935                                                          -              291,065
      Proceeds from public
       offering of common units,
       net of underwriting
       discounts
        and commissions of $7,223                                        -              164,786
      Equity offering costs                                             (4)              (6,236)
      Proceeds from option
       exercises                                                     2,747                3,188
                                                                     -----                -----
            Net cash provided by
             financing activities                                  169,929               74,196
                                                                   -------               ------

    Net (decrease) increase in
     cash and cash equivalents                                      (6,396)              57,089
    Cash and cash equivalents,
     beginning of year                                              59,930               44,692
                                                                    ------               ------
    Cash and cash equivalents,
     end of period                                                 $53,534             $101,781
                                                                   =======             ========


                              COPANO ENERGY, L.L.C. AND SUBSIDIARIES
                              UNAUDITED CONSOLIDATED BALANCE SHEETS

                                                                  September          December
                                                                      30,                31,
                                                                         2011               2010
                                                                         ----               ----

                                                                      (In thousands, except
                                                                        unit information)
                                             ASSETS
    Current assets:
      Cash and cash equivalents                                       $53,534            $59,930
      Accounts receivable, net                                        108,339             96,662
      Risk management assets                                           12,101              7,836
      Prepayments and other current
       assets                                                           8,311              5,179
                                                                        -----              -----
        Total current assets                                          182,285            169,607
                                                                      -------            -------

    Property, plant and equipment,
     net                                                            1,078,948            912,157
    Intangible assets, net                                            179,992            188,585
    Investments in unconsolidated
     affiliates                                                       529,958            604,304
    Escrow cash                                                         1,850              1,856
    Risk management assets                                             17,128             11,943
    Other assets, net                                                  27,739             18,541
                                                                       ------             ------
        Total assets                                               $2,017,900         $1,906,993
                                                                   ==========         ==========

                                LIABILITIES AND MEMBERS' CAPITAL
    Current liabilities:
      Accounts payable                                               $140,792           $117,706
      Accrued interest                                                 19,945             10,621
      Accrued tax liability                                               892                913
      Risk management liabilities                                       7,285              9,357
      Other current liabilities                                        33,948             14,495
                                                                       ------             ------
        Total current liabilities                                     202,862            153,092
                                                                      -------            -------

    Long term debt (includes $0 and
     $546 bond premium as of
     September 30, 2011
      and December 31, 2010,
       respectively)                                                  904,525            592,736
    Deferred tax liability                                              2,135              1,883
    Risk management and other
     noncurrent liabilities                                             2,150              4,525

    Commitments and contingencies
     (Note 9)
    Members' capital:
      Series A convertible preferred
       units, no par value,
       11,399,097 units and
        10,585,197 units issued and
         outstanding as of September
         30, 2011 and
        December 31, 2010, respectively                               285,168            285,172
      Common units, no par value,
       66,270,176 units and
       65,915,173 units issued and
        outstanding as of September 30,
         2011 and December 31, 2010,
         respectively                                               1,164,399          1,161,652
    Paid in capital                                                    59,250             51,743
    Accumulated deficit                                              (592,676)          (313,454)
    Accumulated other comprehensive
     loss                                                              (9,913)           (30,356)
                                                                       ------            -------
                                                                      906,228          1,154,757
                                                                      -------          ---------
        Total liabilities and members'
         capital                                                   $2,017,900         $1,906,993
                                                                   ==========         ==========


                                 COPANO ENERGY, L.L.C. AND SUBSIDIARIES
                                     UNAUDITED RESULTS OF OPERATIONS

                                                    Three Months Ended             Nine Months Ended
                                                    ------------------             -----------------
                                                      September 30,                  September 30,
                                                      -------------                  -------------
                                                         2011             2010              2011         2010
                                                         ----             ----              ----         ----

                                                                      ($ In thousands)
     Total segment gross
      margin(1)                                       $64,842          $57,903          $190,484     $165,863
     Operations and maintenance
      expenses                                         16,091           13,004            46,953       38,337
     Depreciation, amortization
      and impairment                                   21,911           15,218            56,143       46,002
     General and administrative
      expenses                                         10,031            9,869            34,530       31,311
     Taxes other than income                            1,502            1,315             4,029        3,658
     Equity in loss (earnings)
      from unconsolidated
      affiliates(2)                                   161,589           (2,049)          158,581       19,788
                                                      -------           ------           -------       ------
       Operating (loss) income                       (146,282)          20,546          (109,752)      26,767
     Loss on refinancing of
      unsecured debt                                        -                -           (18,233)           -
     Interest and other financing
      costs, net                                      (11,064)         (12,928)          (34,419)     (41,180)
     Provision for income taxes                          (390)            (320)           (1,161)        (660)
     Net (loss) income                               (157,736)           7,298          (163,565)     (15,073)
     Preferred unit distributions                      (8,279)          (7,500)          (24,235)      (7,500)
                                                       ------           ------           -------       ------
     Net loss to common units                       $(166,015)           $(202)        $(187,800)    $(22,573)
                                                    =========            =====         =========     ========

     Total segment gross margin:
       Texas                                          $44,540          $31,218          $135,685      $90,134
       Oklahoma                                        27,876           23,010            79,623       69,106
       Rocky Mountains(3)                                 432            1,091             2,245        3,342
         Segment gross margin                          72,848           55,319           217,553      162,582
       Corporate and other(4)                          (8,006)           2,584           (27,069)       3,281
         Total segment gross
          margin(1)                                   $64,842          $57,903          $190,484     $165,863

     Segment gross margin per
      unit:
       Texas:
         Service throughput ($/MMBtu)                   $0.63            $0.58             $0.71        $0.57
       Oklahoma:
         Service throughput ($/MMBtu)                   $1.05            $0.93             $1.04        $0.97

     Volumes:
       Texas: (5)
         Service throughput (MMBtu/
          d)(6)                                       765,744          590,116           694,802      577,678
         Pipeline throughput (MMBtu/
          d)                                          463,321          319,538           436,210      321,450
         Plant inlet volumes (MMBtu/
          d)                                          686,398          516,949           612,405      481,285
         NGLs produced (Bbls/d)                        30,904           19,685            27,040       17,818
       Oklahoma:(7)
         Service throughput (MMBtu/
          d)(6)                                       288,440          270,184           286,320      259,710
         Plant inlet volumes (MMBtu/
          d)                                          158,070          156,676           160,737      156,771
         NGLs produced (Bbls/d)                        17,453           16,541            17,498       16,180

     Capital Expenditures:
       Maintenance capital
        expenditures                                   $3,510           $3,290           $11,111       $6,370
       Expansion capital
        expenditures                                   82,675           29,290           203,576      101,232
         Total capital expenditures                   $86,185          $32,580          $214,687     $107,602

     Operations and maintenance
      expenses:
       Texas                                           $9,082           $6,779           $26,815      $20,845
       Oklahoma                                         6,930            6,163            19,943       17,266
       Rocky Mountains                                     79               62               195          226
         Total operations and
          maintenance expenses                        $16,091          $13,004           $46,953      $38,337


        Total segment gross margin is a non-GAAP financial measure.  Please
        read "- How We Evaluate Our Operations" for a reconciliation of total
        segment gross margin to its most directly comparable GAAP measure of
    (1) operating income.
        Includes results and volumes associated with our unconsolidated
        affiliates.  The following table summarizes the throughput for the
    (2) periods indicated:


                                             Three Months         Nine Months
                                                           Ended               Ended
                                             ------------     September 30,
                                            September 30,        -------------
                                             2011     2010     2011     2010
                                             ----     ----     ----     ----
    Bighorn
     and Fort
     Union(a)               MMBtu/d     670,543  913,730  595,302  914,967
    Southern Dome
       Plant
        inlet               MMBtu/d      11,970   12,338   11,630   13,046
       NGLs
        produced             Bbls/d         429      444      418      466
    Webb
     Duval(b)               MMBtu/d      48,628   53,668   48,705   56,145
    Eagle Ford
     Gathering              MMBtu/d      58,295        -   58,295        -
    Liberty
     Pipeline
     Group                   Bbls/d       4,252        -    4,252        -
    ___________________________
    (a) The volume decline is primarily due to certain
     Fort Union shippers diverting gas volumes to
     TransCanada's Bison Pipeline upon its start up in
     January 2011.  Fort Union volumes do not reflect
     an additional 223,557 MMBtu/d and 279,918 MMBtu/
     d in long-term contractually committed volumes
     that Fort Union did not gather but which were the
     basis of payments received by Fort Union for the
     three and nine months ended September 30, 2011,
     respectively.
    (b) Net of intercompany volumes.


        Rocky Mountains segment gross margin includes results from producer
        services, including volumes purchased for resale, volumes gathered
        under firm capacity gathering agreements with Fort Union, volumes
        transported using our firm capacity agreements with Wyoming Interstate
        Gas Company and compressor rental services provided to Bighorn.
        Excludes results and volumes associated with our interest in Bighorn
    (3) and Fort Union.
        Corporate and other includes results attributable to our commodity risk
    (4) management activities.
        Plant inlet volumes and NGLs produced represent total volumes processed
        and produced by the Texas segment at all plants, including plants owned
    (5) by the Texas segment and plants owned by third parties.
        "Service throughput" means the volume of natural gas delivered to our
        wholly owned processing plants by third-party pipelines plus our
        "pipeline throughput," which is the volume of natural gas transported
    (6) or gathered through our pipelines.
        Plant inlet volumes and NGLs produced represent total volumes processed
        and produced by the Oklahoma segment at all plants, including plants
    (7) owned by the Oklahoma segment and plants owned by third parties.


                                    COPANO ENERGY, L.L.C. AND SUBSIDIARIES
                                     UNAUDITED NON GAAP FINANCIAL MEASURES

                                                            Three Months
                                                                Ended                   Nine Months Ended
                                                           -------------                -----------------
                                                           September 30,                  September 30,
                                                           -------------                  -------------

                                                              2011             2010              2011         2010
                                                              ----             ----              ----         ----

                                                                         ($ In thousands)
    Reconciliation of total segment
     gross margin to operating
     (loss) income:
      Operating (loss) income                            $(146,282)         $20,546         $(109,752)     $26,767
      Add:                                                  16,091           13,004            46,953       38,337
        Operations and maintenance
         expenses
        Depreciation, amortization and
         impairment                                         21,911           15,218            56,143       46,002
        General and administrative
         expenses                                           10,031            9,869            34,530       31,311
        Taxes other than income                              1,502            1,315             4,029        3,658
        Equity in loss (earnings) from
         unconsolidated affiliates                         161,589           (2,049)          158,581       19,788
                                                           -------           ------           -------       ------
    Total segment gross margin                             $64,842          $57,903          $190,484     $165,863
                                                           =======          =======          ========     ========

    Reconciliation of EBITDA,
     adjusted EBITDA and total
     distributable
      cash flow to net (loss) income:
      Net (loss) income                                  $(157,736)          $7,298         $(163,565)    $(15,073)
      Add:                                                  21,911           15,218            56,143       46,002
        Depreciation, amortization and
         impairment
        Interest and other financing
         costs                                              11,080           12,943            34,450       41,239
        Provision for income taxes                             390              320             1,161          660
                                                               ---              ---             -----          ---
    EBITDA                                                (124,355)          35,779           (71,811)      72,828
      Add:                                                   7,442            8,163            22,069       24,211
        Amortization of commodity
         derivative options
        Distributions from
         unconsolidated affiliates                           6,757            6,563            20,329       19,554
        Loss on refinancing of unsecured
         debt                                                    -                -            18,233            -
        Equity-based compensation                            2,093            2,448             9,184        7,849
        Equity in loss (earnings) from
         unconsolidated affiliates                         161,589           (2,049)          158,581       19,788
        Unrealized (gain) loss from
         commodity risk management
         activities                                         (2,332)             389            (2,695)         150
        Other non-cash operating items                         576             (295)             (272)       1,933
                                                               ---             ----              ----        -----
    Adjusted EBITDA                                         51,770           50,998           153,618      146,313
      Less:                                                (11,029)         (11,856)          (33,623)     (39,171)
        Interest expense
        Current income tax expense and
         other                                                (305)            (141)             (929)        (740)
        Maintenance capital expenditures                    (3,510)          (3,290)          (11,111)      (6,370)
                                                            ------           ------           -------       ------
    Total distributable cash flow                          $36,926          $35,711          $107,955     $100,032
                                                           =======          =======          ========     ========


                                                   Three Months
                                                       Ended
                                                       ------------
                                                  September 30,
                                                  -------------
                                                     2011            2010
                                                     ----            ----
                                                  (In thousands,
                                                  except per unit
                                                   information)
    Reconciliation of adjusted net income and
     adjusted net income per unit:
      Net loss to common units                  $(166,015)          $(202)
      Non-cash impairment charge                  170,000               -
                                                  -------             ---
      Adjusted net income to common units          $3,985           $(202)
                                                   ======           =====
      Diluted net loss per common unit             $(2.51)     $        -
                                                   ======             ===
      Diluted adjusted net income per common
       unit                                         $0.06      $        -
                                                    =====             ===
      Weighted average number of diluted common
       units                                       66,246          65,658
      Restricted units, phantom units, options,
       unit appreciation rights and contingent
       units                                          838               -
                                                      ---             ---
      Adjusted weighted average number of
       diluted common units                        67,084          65,658
                                                   ======          ======

SOURCE Copano Energy, L.L.C.


Source: PR Newswire