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Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Form 10-Q
 
 
     
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the quarterly period ended March 31, 2010
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number: 001-32329
 
 
 
 
Copano Energy, L.L.C.
(Exact Name of Registrant as Specified in Its Charter)
 
     
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  51-0411678
(I.R.S. Employer
Identification No.)
 
 
2727 Allen Parkway, Suite 1200
Houston, Texas 77019
(Address of Principal Executive Offices)
 
 
(713) 621-9547
(Registrant’s telephone number, including area code)
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  o Yes     o No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
There were 65,476,911 common units of Copano Energy, L.L.C. outstanding at April 30, 2010. Copano Energy, L.L.C.’s common units trade on The NASDAQ Stock Market LLC under the symbol “CPNO.”
 


 

 
TABLE OF CONTENTS
 
                 
        Page
 
PART I — FINANCIAL INFORMATION
  Item 1.     Financial Statements     3  
        Unaudited Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009     3  
        Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009     4  
        Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009     5  
        Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Three Months Ended March 31, 2010 and 2009     6  
        Notes to Unaudited Consolidated Financial Statements     7  
  Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     34  
  Item 3.     Quantitative and Qualitative Disclosures About Market Risk     50  
  Item 4.     Controls and Procedures     52  
 
PART II — OTHER INFORMATION
  Item 1.     Legal Proceedings     53  
  Item 1A.     Risk Factors     53  
  Item 6.     Exhibits     54  
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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Item 1.   Financial Statements.
 
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
 
                 
    March 31,
    December 31,
 
    2010     2009  
    (In thousands, except unit information)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 54,148     $ 44,692  
Accounts receivable, net
    89,203       91,156  
Risk management assets
    30,334       36,615  
Prepayments and other current assets
    3,770       4,937  
                 
Total current assets
    177,455       177,400  
                 
Property, plant and equipment, net
    850,444       841,323  
Intangible assets, net
    187,858       190,376  
Investment in unconsolidated affiliates
    613,825       618,503  
Escrow cash
    1,858       1,858  
Risk management assets
    17,170       15,381  
Other assets, net
    21,488       22,571  
                 
Total assets
  $ 1,870,098     $ 1,867,412  
                 
 
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
               
Accounts payable
  $ 112,590     $ 111,021  
Accrued interest
    9,935       11,921  
Accrued tax liability
    879       672  
Risk management liabilities
    7,426       9,671  
Other current liabilities
    15,788       9,358  
                 
Total current liabilities
    146,618       142,643  
                 
Long-term debt (includes $608 and $628 bond premium as of March 31, 2010 and December 31, 2009, respectively)
    717,798       852,818  
Deferred tax provision
    1,889       1,862  
Risk management and other noncurrent liabilities
    7,474       10,063  
Commitments and contingencies (Note 9)
               
Members’ capital:
               
Common units, no par value, 65,468,775 units and 54,670,029 units issued and outstanding as of March 31, 2010 and December 31, 2009, respectively
    1,156,889       879,504  
Class D units, no par value, 0 and 3,245,817 units issued and outstanding as of March 31, 2010 and December 31, 2009, respectively
          112,454  
Paid-in capital
    45,624       42,518  
Accumulated deficit
    (191,432 )     (158,267 )
Accumulated other comprehensive loss
    (14,762 )     (16,183 )
                 
      996,319       860,026  
                 
Total liabilities and members’ capital
  $ 1,870,098     $ 1,867,412  
                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
 
                 
    Three Months Ended March 31,  
    2010     2009  
    (In thousands, except per unit information)  
 
Revenue:
               
Natural gas sales
  $ 120,216     $ 94,979  
Natural gas liquids sales
    119,318       80,831  
Transportation, compression and processing fees
    13,114       14,999  
Condensate and other
    14,018       10,269  
                 
Total revenue
    266,666       201,078  
                 
Costs and expenses:
               
Cost of natural gas and natural gas liquids(1)
    209,865       143,319  
Transportation(1)
    5,676       5,984  
Operations and maintenance
    12,103       12,672  
Depreciation and amortization
    15,201       13,105  
General and administrative
    10,542       10,725  
Taxes other than income
    1,162       786  
Equity in earnings from unconsolidated affiliates
    (1,795 )     (1,484 )
                 
Total costs and expenses
    252,754       185,107  
                 
Operating income
    13,912       15,971  
Other income (expense):
               
Interest and other income
    7       46  
Gain on retirement of unsecured debt
          3,939  
Interest and other financing costs
    (14,945 )     (14,448 )
                 
(Loss) income before income taxes and discontinued operations
    (1,026 )     5,508  
Provision for income taxes
    (234 )     (164 )
                 
(Loss) income from continuing operations
    (1,260 )     5,344  
Discontinued operations, net of tax (Note 13)
          561  
                 
Net (loss) income
  $ (1,260 )   $ 5,905  
                 
Basic net (loss) income per common unit:
               
(Loss) income per common unit from continuing operations
  $ (0.02 )   $ 0.10  
Income per common unit from discontinued operations
          0.01  
                 
Net (loss) income per common unit
  $ (0.02 )   $ 0.11  
                 
Weighted average number of common units
    58,206       54,012  
Diluted net (loss) income per common unit:
               
(Loss) income per common unit from continuing operations
  $ (0.02 )   $ 0.09  
Income per common unit from discontinued operations
          0.01  
                 
Net (loss) income per common unit
  $ (0.02 )   $ 0.10  
                 
Weighted average number of common units
    58,206       57,814  
 
 
(1) Exclusive of operations and maintenance and depreciation and amortization shown separately below.
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Three Months
 
    Ended March 31,  
    2010     2009  
    (In thousands)  
 
Cash Flows From Operating Activities:
               
Net (loss) income
  $ (1,260 )   $ 5,905  
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
               
Depreciation and amortization
    15,201       13,165  
Amortization of debt issue costs
    895       1,270  
Equity in earnings from unconsolidated affiliates
    (1,795 )     (1,484 )
Distributions from unconsolidated affiliates
    5,765       5,371  
Gain on retirement of unsecured debt
          (3,939 )
Non-cash loss (gain) on risk management activities, net
    533       (239 )
Equity-based compensation
    2,703       1,705  
Deferred tax provision
    27       12  
Other non-cash items
    (301 )     332  
Changes in assets and liabilities:
               
Accounts receivable
    2,124       28,277  
Prepayments and other current assets
    1,167       1,060  
Risk management activities
    597       9,188  
Accounts payable
    2,063       (22,925 )
Other current liabilities
    1,445       (2,300 )
                 
Net cash provided by operating activities
    29,164       35,398  
                 
Cash Flows From Investing Activities:
               
Additions to property, plant and equipment
    (19,162 )     (19,423 )
Additions to intangible assets
    (263 )     (417 )
Investment in unconsolidated affiliates
    (435 )     (632 )
Distributions from unconsolidated affiliates
    972       1,560  
Proceeds from sale of assets
    259        
Other
    188       (539 )
                 
Net cash used in investing activities
    (18,441 )     (19,451 )
                 
Cash Flows From Financing Activities:
               
Proceeds from long-term debt
    35,000       50,000  
Repayment of long-term debt
    (170,000 )      
Retirement of unsecured debt
          (14,286 )
Distributions to unitholders
    (31,457 )     (31,057 )
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223
    164,786        
Equity offering costs
    (272 )      
Proceeds from option exercises
    676       5  
                 
Net cash (used in) provided by financing activities
    (1,267 )     4,662  
                 
Net increase in cash and cash equivalents
    9,456       20,609  
Cash and cash equivalents, beginning of year
    44,692       63,684  
                 
Cash and cash equivalents, end of period
  $ 54,148     $ 84,293  
                 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.


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                                                    Accumulated
             
    Common     Class C     Class D                 Other
          Total
 
    Number
    Common
    Number
    Class C
    Number
    Class D
    Paid-in
    Accumulated
    Comprehensive
          Comprehensive
 
    of Units     Units     of Units     Units     of Units     Units     Capital     Deficit     (Loss) Income     Total     Income (Loss)  
 
Balance, December 31, 2009
    54,670     $ 879,504           $       3,246     $ 112,454     $ 42,518     $ (158,267 )   $ (16,183 )   $ 860,026          
Conversion of Class D units into common units
    3,246       112,454                   (3,246 )     (112,454 )                           $  
Distributions to unitholders
                                              (31,905 )           (31,905 )      
Issuance of common units to public
    7,446       172,008                                                 172,008        
Equity offering costs
          (7,753 )                                               (7,753 )      
Equity-based compensation
    107       676                               3,106                   3,782        
Net loss
                                              (1,260 )           (1,260 )     (1,260 )
Derivative settlements reclassified to income
                                                    855       855       855  
Unrealized gain-change in fair value of derivatives
                                                    566       566       566  
                                                                                         
Comprehensive income
                                                                                  $ 161  
                                                                                         
Balance, March 31, 2010
    65,469     $ 1,156,889           $           $     $ 45,624     $ (191,432 )   $ (14,762 )   $ 996,319          
                                                                                         
 
                                                                                         
                                                    Accumulated
             
    Common     Class C     Class D           Accumulated
    Other
          Total
 
    Number
    Common
    Number
    Class C
    Number
    Class D
    Paid-in
    Earnings
    Comprehensive
          Comprehensive
 
    of Units     Units     of Units     Units     of Units     Units     Capital     (Deficit)     Income (Loss)     Total     Income (Loss)  
    (In thousands)  
 
Balance, December 31, 2008
    53,965     $ 865,343       395     $ 13,497       3,246     $ 112,454     $ 33,734     $ (54,696 )   $ 67,626     $ 1,037,958          
Distributions to unitholders
                                              (31,462 )           (31,462 )   $  
Equity-based compensation
    104       5                               3,156                   3,161        
Net income
                                              5,905             5,905       5,905  
Derivative settlements reclassified to income
                                                    (14,696 )     (14,696 )     (14,696 )
Unrealized gain-change in fair value of derivatives
                                                    7,013       7,013       7,013  
                                                                                         
Comprehensive loss
                                                                                  $ (1,778 )
                                                                                         
Balance, March 31, 2009
    54,069     $ 865,348       395     $ 13,497       3,246     $ 112,454     $ 36,890     $ (80,253 )   $ 59,943     $ 1,007,879          
                                                                                         
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
 
Note 1 — Organization and Basis of Presentation
 
Organization
 
Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities owning businesses operating under the Copano name since 1992. We, through our subsidiaries, provide midstream services to natural gas producers, including natural gas gathering, compression, dehydration, treating, marketing, transportation, processing, conditioning and fractionation services. Our assets are located in Oklahoma, Texas, Wyoming and Louisiana. Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C., its subsidiaries and entities it manages or operates.
 
Our natural gas pipelines collect natural gas from wellheads or designated points near producing wells and deliver these volumes to our processing plants, third-party processing plants, third-party pipelines, local distribution companies, power generation facilities and industrial consumers. Our processing plants take delivery of natural gas from our gathering systems as well as third-party pipelines. The natural gas is then treated as needed to remove contaminants and then conditioned or processed to extract mixed NGLs. After treating and processing or conditioning, we deliver the residue gas primarily to third-party pipelines through plant interconnects and sell the NGLs, in some cases after separating the NGLs into select component products, to third parties through our plant interconnects or our NGL pipelines. We refer to our operations (i) conducted through our subsidiaries operating in Oklahoma, including our crude oil pipeline which was sold in October 2009, collectively as our “Oklahoma” segment, (ii) conducted through our subsidiaries operating in Texas and Louisiana collectively as our “Texas” segment and (iii) conducted through our subsidiaries operating in Wyoming collectively as our “Rocky Mountains” segment.
 
Basis of Presentation and Principles of Consolidation
 
The accompanying unaudited consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in our unaudited consolidated financial statements.
 
Because we sold our crude oil pipeline operations in October 2009, the results related to these operations have been classified as “discontinued operations” on the accompanying unaudited consolidated statements of operations for the three months ended March 31, 2009. Unless otherwise indicated, information about the statements of operations that is presented in the notes to unaudited consolidated financial statements relates only to our continuing operations. See Note 13 for additional details.
 
The accompanying unaudited consolidated financial statements have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of our management, necessary for a fair presentation of our results of operations for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations.
 
However, our management believes that the disclosures are adequate to make the information presented not misleading. In the preparation of these financial statements, we evaluated subsequent events through the issuance date of the financial statements. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K and Amendment No. 1 for the year ended December 31, 2009.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 2 — New Accounting Pronouncements
 
Fair Value Measurements
 
In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements”, which updates Accounting Standards Codification (“ASC”) 820-10 to require new disclosure of amounts transferred in and out of Level 1 and Level 2 of the fair value hierarchy and presentation of a reconciliation of changes in fair value amounts in the Level 3 fair value hierarchy on a gross basis rather than a net basis. Additionally, ASU 2010-06 requires greater disaggregation of the assets and liabilities for which fair value measurements are presented and requires expanded disclosure of the valuation techniques and inputs used for Level 2 and Level 3 fair value measurements. We implemented ASU 2010-06 as of March 31, 2010. See Note 11 for the required additional disclosures.
 
Note 3 — Intangible Assets
 
Our intangible assets consist of rights-of-way, easements, contracts and acquired customer relationships. We amortize existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable. Upon adoption of the ASC 350-30, initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. Amortization expense was $2,780,000 and $2,751,000 for the three months ended March 31, 2010 and 2009, respectively. Estimated aggregate amortization expense remaining for 2010 and each of the five succeeding fiscal years is approximately: 2010 — $8,291,000; 2011 — $11,055,000; 2012 — $10,991,000; 2013 — $10,810,000; 2014 — $10,643,000; and 2015 — $10,608,000. Intangible assets consisted of the following (in thousands):
 
                 
    March 31,
    December 31,
 
    2010     2009  
 
Rights-of-way and easements, at cost
  $ 116,384     $ 116,122  
Less accumulated amortization for rights-of-way and easements
    (19,450 )     (18,204 )
Contracts
    107,916       107,916  
Less accumulated amortization for contracts
    (20,786 )     (19,330 )
Customer relationships
    4,864       4,864  
Less accumulated amortization for customer relationships
    (1,070 )     (992 )
                 
Intangible assets, net
  $ 187,858     $ 190,376  
                 
 
As of March 31, 2010 and 2009, the weighted average amortization period for all of our intangible assets was 20 years and 21 years, respectively. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 22 years, 18 years and 12 years, respectively, as of March 31, 2010. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 23 years, 19 years and 13 years, respectively, as of March 31, 2009.
 
Note 4 — Investment in Unconsolidated Affiliates
 
We own a 62.5% equity investment in Webb/Duval Gatherers (“Webb Duval”), a Texas general partnership, a majority interest in Southern Dome, LLC (“Southern Dome”), a Delaware limited liability company, a 51% equity investment in Bighorn Gas Gathering, L.L.C. (“Bighorn”), a Delaware limited liability company and a 37.04% equity investment in Fort Union Gas Gathering, L.L.C. (“Fort Union”), a Delaware limited liability company.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 4 — Investment in Unconsolidated Affiliates (Continued)
 
No restrictions exist under Webb Duval’s, Southern Dome’s, or Bighorn’s partnership or operating agreements that limit these entities’ ability to pay distributions to their respective partners or members after consideration of their respective current and anticipated cash needs, including debt service obligations. Fort Union can distribute cash to its members only if its ratio of net operating cash flow to debt service is not less than 1.25 to 1.00 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash. As of March 31, 2010, Fort Union is in compliance with all financial covenants.
 
The summarized financial information for our equity investments as of and for the three months ended March 31, 2010 is as follows (in thousands):
 
                                 
    Bighorn     Fort Union     Southern Dome     Webb Duval  
 
Operating revenue
  $ 8,049     $ 14,160     $ 7,687     $ 511  
Operating expenses
    (3,122 )     (2,189 )     (6,162 )     (518 )
Depreciation and amortization
    (1,270 )     (1,730 )     (186 )     (191 )
Interest income (expense) and other
    4       (1,002 )     2        
                                 
Net income (loss)
    3,661       9,239       1,341       (198 )
Ownership %
    51 %     37.04 %     69.5 %     62.5 %
                                 
      1,867       3,422       932       (124 )
Priority allocation of earnings and other
    170             (18 )      
Copano’s share of management fees charged
    71       22       43       35  
Amortization of difference between the carried investment and the underlying equity in net assets
    (3,042 )     (1,606 )     (2 )     5  
                                 
Equity in (loss) earnings from unconsolidated affiliates
  $ (934 )   $ 1,838     $ 955     $ (84 )
                                 
Distributions
  $ 2,897     $ 2,778     $ 1,043     $  
                                 
Current assets
  $ 6,572     $ 12,619     $ 3,986     $ 430  
Noncurrent assets
    91,897       211,094       15,381       5,995  
Current liabilities
    (1,383 )     (21,451 )     (5,244 )     (945 )
Noncurrent liabilities
    (244 )     (84,592 )           (59 )
                                 
Net assets
  $ 96,842     $ 117,670     $ 14,123     $ 5,421  
                                 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 4 — Investment in Unconsolidated Affiliates (Continued)
 
The summarized financial information for our equity investments as of and for the three months ended March 31, 2009 is as follows (in thousands):
 
                                 
    Bighorn     Fort Union     Southern Dome     Webb Duval  
 
Operating revenue
  $ 8,900     $ 15,121     $ 3,247     $ 498  
Operating expenses
    (3,315 )     (1,439 )     (2,808 )     (395 )
Depreciation and amortization
    (1,142 )     (1,948 )     (187 )     (197 )
Interest (expense) income and other
          (1,365 )     2        
                                 
Net income (loss)
    4,443       10,369       254       (94 )
Ownership %
    51 %     37.04 %     69.5 %     62.5 %
                                 
      2,266       3,841       176       (59 )
Priority allocation of earnings and other
    148       (225 )            
Copano’s share of management fees charged
    60       21       43       34  
Amortization of difference between the carried investment and the underlying equity in net assets
    (3,215 )     (1,606 )     (2 )     5  
                                 
Equity in (loss) earnings from unconsolidated affiliates
  $ (741 )   $ 2,031     $ 217     $ (20 )
                                 
Distributions
  $ 3,209     $ 2,778     $ 626     $ 281  
                                 
Current assets
  $ 9,037     $ 15,086     $ 2,372     $ 627  
Noncurrent assets
    97,145       213,672       16,190       6,756  
Current liabilities
    (2,091 )     (20,243 )     (3,107 )     (471 )
Noncurrent liabilities
          (99,708 )           (55 )
                                 
Net assets
  $ 104,091     $ 108,807     $ 15,455     $ 6,857  
                                 
 
Note 5 — Long-Term Debt
 
A summary of our debt follows (in thousands):
 
                 
    March 31,
    December 31,
 
    2010     2009  
 
Long-term debt:
               
Credit Facility
  $ 135,000     $ 270,000  
Senior Notes:
               
8.125% senior unsecured notes due 2016
    332,665       332,665  
Unamortized bond premium-senior notes due 2016
    608       628  
7.75% senior unsecured notes due 2018
    249,525       249,525  
                 
Total Senior Notes
    582,798       582,818  
                 
Total
  $ 717,798     $ 852,818  
                 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 5 — Long-Term Debt (Continued)
 
Senior Secured Revolving Credit Facility
 
As of March 31, 2010, we had $135.0 million of outstanding borrowings under our $550 million senior secured revolving credit facility (the “Credit Facility”) with Bank of America, N.A., as Administrative Agent. The Credit Facility matures on October 18, 2012. Future borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restrictions so long as we are in compliance with its terms, including the financial covenants described below. The Credit Facility provides for up to $50.0 million in standby letters of credit. As of March 31, 2010 and December 31, 2009, we had no letters of credit outstanding.
 
The effective average interest rate on borrowings under the Credit Facility for the three months ended March 31, 2010 and 2009 was 5.3% and 4.8%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility for those periods was 0.25%. Interest and other financing costs related to the Credit Facility totaled $1,920,000 and $2,970,000 for the three months ended March 31, 2010 and 2009, respectively. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the Credit Facility, and as of March 31, 2010, the unamortized portion of debt issue costs totaled $5,454,000.
 
The Credit Facility contains covenants (some of which require that we make certain subjective representations and warranties), including financial covenants that require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios as follows:
 
  •  a minimum EBITDA to interest expense ratio (using four quarters’ EBITDA as defined under the Credit Facility) of 2.5 to 1.0;
 
  •  a maximum total debt to EBITDA ratio of 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).
 
EBITDA for the purposes of the Credit Facility is our EBITDA with certain negotiated adjustments.
 
At March 31, 2010, our ratio of EBITDA to interest expense was 3.5x, and our ratio of total debt to EBITDA was 3.7x. Based on our current four-quarter EBITDA, as defined under the Credit Facility, we could borrow an additional $247 million before reaching our maximum total debt to EBITDA ratio of 5.0 to 1.0. If we failed to comply with the financial or other covenants under our Credit Facility or experienced a material adverse effect on our operations, business, properties, liabilities or financial or other condition, we would be unable to borrow under our Credit Facility, and could be in default after specified notice and cure periods. If an event of default exists under the Credit Facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the Credit Facility.
 
We are in compliance with the financial covenants under the Credit Facility as of March 31, 2010.
 
Senior Notes
 
8.125% Senior Notes Due 2016.  At March 31, 2010, the aggregate principal amount of our 8.125% senior unsecured notes due 2016 (the “2016 Notes”) outstanding was $332,665,000.
 
Interest and other financing costs related to the 2016 Notes totaled $6,951,000 and $6,953,000 for the three months ended March 31, 2010 and 2009, respectively. Interest on the 2016 Notes is payable each March 1 and September 1. Costs of issuing the 2016 Notes are being amortized over the term of the 2016 Notes and, as of March 31, 2010, the unamortized portion of debt issue costs totaled $5,061,000.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 5 — Long-Term Debt (Continued)
 
7.75% Senior Notes Due 2018.  At March 31, 2010, the aggregate principal amount of 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2016 Notes, the “Senior Notes”) outstanding was $249,525,000.
 
Interest and other financing costs relating to the 2018 Notes totaled $4,971,000 and $5,523,000 for the three months ended March 31, 2010 and 2009, respectively. Interest on the 2018 Notes is payable each June 1 and December 1. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of March 31, 2010, the unamortized portion of debt issue costs totaled $4,444,000.
 
General.  The indentures governing our Senior Notes include an incurrence covenant which restricts our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the Senior Notes indentures) is at least 1.75x. For the twelve months ended March 31, 2010, our ratio of EBITDA to fixed charges was 3.3x, which is in compliance with this incurrence covenant under the indentures governing our Senior Notes.
 
Condensed consolidating financial information for Copano and its wholly owned subsidiaries is presented below.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Note 5 — Long Term Debt (Continued)
 
CONDENSED CONSOLIDATING BALANCE SHEETS
 
                                                                                                 
    March 31, 2010     December 31, 2009  
                      Investment in
                                  Investment in
             
                Guarantor
    Non-Guarantor
                            Guarantor
    Non-Guarantor
             
    Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total     Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total  
    (In thousands)  
 
ASSETS
                                                                                               
Current assets:
                                                                                               
Cash and cash equivalents
  $ 13,054     $     $ 41,094     $     $     $ 54,148     $ 3,861     $     $ 40,831     $     $     $ 44,692  
Accounts receivable, net
    66             89,137                   89,203       29             91,127                   91,156  
Intercompany receivable
    14,253       (1 )     (14,252 )                       21,034             (21,034 )                  
Risk management assets
                30,334                   30,334                     36,615                   36,615  
Prepayments and other current assets
    2,356             1,414                   3,770       3,610             1,327                   4,937  
Discontinued operations
                                                                       
                                                                                                 
Total current assets
    29,729       (1 )     147,727                   177,455       28,534             148,866                   177,400  
                                                                                                 
Property, plant and equipment, net
    86             850,358                   850,444       96             841,227                   841,323  
Intangible assets, net
                187,858                   187,858                   190,376                   190,376  
Investment in unconsolidated affiliates
                613,825       613,825       (613,825 )     613,825                   618,503       618,503       (618,503 )     618,503  
Investment in consolidated subsidiaries
    1,685,254                         (1,685,254 )           1,684,994                         (1,684,994 )      
Escrow cash
                1,858                   1,858                   1,858                   1,858  
Risk management assets
                17,170                   17,170                   15,381                   15,381  
Other assets, net
    14,959             6,529                   21,488       15,854             6,717                   22,571  
                                                                                                 
Total assets
  $ 1,730,028     $ (1 )   $ 1,825,325     $ 613,825     $ (2,299,079 )   $ 1,870,098     $ 1,729,478     $     $ 1,822,928     $ 618,503     $ (2,303,497 )   $ 1,867,412  
                                                                                                 
                                                                                                 
LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
                                                                                               
Current liabilities:
                                                                                               
Accounts payable
  $ 419     $     $ 112,171     $     $     $ 112,590     $     $     $ 111,021     $     $     $ 111,021  
Accrued interest
    9,176             759                   9,935       11,146             775                   11,921  
Accrued tax liability
    879                               879       672                               672  
Risk management liabilities
                7,426                   7,426                   9,671                   9,671  
Other current liabilities
    3,265             12,523                   15,788       2,637             6,721                   9,358  
                                                                                                 
Total current liabilities
    13,739             132,879                   146,618       14,455             128,188                   142,643  
                                                                                                 
Long-term debt
    717,798                               717,798       852,818                               852,818  
Deferred tax provision
    1,889                               1,889       1,862                               1,862  
Risk management and other noncurrent liabilities
    283             7,191                   7,474       317             9,746                   10,063  
Members’/Partners’ capital:
                                                                                               
Common units
    1,156,889                               1,156,889       879,504                               879,504  
Class D units
                                        112,454                               112,454  
Paid-in capital
    45,624       1       1,172,582       589,302       (1,761,885 )     45,624       42,518       1       1,191,268       595,775       (1,787,044 )     42,518  
Accumulated (deficit) earnings
    (191,432 )     (2 )     527,434       24,523       (551,955 )     (191,432 )     (158,267 )     (1 )     509,909       22,728       (532,636 )     (158,267 )
Other comprehensive (loss) income
    (14,762 )           (14,761 )           14,761       (14,762 )     (16,183 )           (16,183 )           16,183       (16,183 )
                                                                                                 
      996,319       (1 )     1,685,255       613,825       (2,299,079 )     996,319       860,026             1,684,994       618,503       (2,303,497 )     860,026  
                                                                                                 
Total liabilities and members’/partners’ capital
  $ 1,730,028     $ (1 )   $ 1,825,325     $ 613,825     $ (2,299,079 )   $ 1,870,098     $ 1,729,478     $     $ 1,822,928     $ 618,503     $ (2,303,497 )   $ 1,867,412  
                                                                                                 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Note 5 — Long Term Debt (Continued)
 
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
 
                                                                                                 
    Three Months Ended March 31,  
    2010     2009  
                      Investment in
                                  Investment in
             
                Guarantor
    Non-Guarantor
                            Guarantor
    Non-Guarantor
             
    Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total     Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total  
    (In thousands)  
 
Revenue:
                                                                                               
Natural gas sales
  $     $     $ 120,216     $     $     $ 120,216     $     $     $ 94,979     $     $     $ 94,979  
Natural gas liquids sales
                119,318                   119,318                   80,831                   80,831  
Transportation, compression and processing fees
                13,114                   13,114                   14,999                   14,999  
Condensate and other
                14,018                   14,018                   10,269                   10,269  
                                                                                                 
Total revenue
                266,666                   266,666                   201,078                   201,078  
                                                                                                 
Costs and expenses:
                                                                                               
Cost of natural gas and natural gas liquids
                209,865                   209,865                   143,319                   143,319  
Transportation
                5,676                   5,676                   5,984                   5,984  
                                                                                                 
Operations and maintenance
                12,103                   12,103       270             12,402                   12,672  
                                                                                                 
Depreciation and amortization
    10             15,191                   15,201       10             13,095                   13,105  
                                                                                                 
General and administrative
    5,195             5,347                   10,542       6,451             4,274                   10,725  
                                                                                                 
Taxes other than income
                1,162                   1,162                   786                   786  
                                                                                                 
Equity in earnings from unconsolidated affiliates
                (1,795 )     (1,795 )     1,795       (1,795 )                 (1,484 )     (1,484 )     1,484       (1,484 )
                                                                                                 
Total costs and expenses
    5,205             247,549       (1,795 )     1,795       252,754       6,731             178,376       (1,484 )     1,484       185,107  
                                                                                                 
Operating (loss) income
    (5,205 )           19,117       1,795       (1,795 )     13,912       (6,731 )           22,702       1,484       (1,484 )     15,971  
Other income (expense):
                                                                                               
Interest and other income
                7                   7                   46                   46  
Gain on retirement of unsecured debt
                                        3,939                               3,939  
Interest and other financing costs
    (13,347 )           (1,598 )                 (14,945 )     (13,417 )           (1,031 )                 (14,448 )
                                                                                                 
(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries
    (18,552 )           17,526       1,795       (1,795 )     (1,026 )     (16,209 )           21,717       1,484       (1,484 )     5,508  
                                                                                                 
Provision for income taxes
    (234 )                             (234 )     (164 )                             (164 )
                                                                                                 
(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries
    (18,786 )           17,526       1,795       (1,795 )     (1,260 )     (16,373 )           21,717       1,484       (1,484 )     5,344  
Discontinued operations, net of tax
                                                    561                   561  
                                                                                                 
(Loss) income before equity earnings from consolidated subsidiaries
    (18,786 )           17,526       1,795       (1,795 )     (1,260 )     (16,373 )           22,278       1,484       (1,484 )     5,905  
Equity in earnings from consolidated subsidiaries
    17,526                         (17,526 )           22,278                         (22,278 )      
                                                                                                 
Net (loss) income
  $ (1,260 )   $     $ 17,526     $ 1,795     $ (19,321 )   $ (1,260 )   $ 5,905     $     $ 22,278     $ 1,484     $ (23,762 )   $ 5,905  
                                                                                                 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Note 5 — Long Term Debt (Continued)
 
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
 
                                                                                                 
    Three Month Ended March 31,  
    2010     2009  
                      Investment in
                                  Investment in
             
                Guarantor
    Non-Guarantor
                            Guarantor
    Non-Guarantor
             
    Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total     Parent     Co-Issuer     Subsidiaries     Subsidiaries     Eliminations     Total  
    (In thousands)  
 
Cash Flows From Operating Activities:
                                                                                               
Net cash provided by (used in) operating activities
  $ (12,540 )   $     $ 41,704     $ 5,765     $ (5,765 )   $ 29,164     $ 8,667     $     $ 26,731     $ 5,371     $ (5,371 )   $ 35,398  
                                                                                                 
Cash Flows From Investing Activities:
                                                                       
Additions to property, plant and equipment
                (19,425 )                 (19,425 )                 (19,840 )                 (19,840 )
Investment in unconsolidated affiliates
                (435 )     (435 )     435       (435 )                 (632 )     (632 )     632       (632 )
Distributions from unconsolidated affiliates
                972       972       (972 )     972                   1,560       1,560       (1,560 )     1,560  
Investment in consolidated affiliates
                                        (25 )                       25        
Distributions from consolidated affiliates
    23,000                         (23,000 )           6,000                         (6,000 )      
Proceeds from sale of assets
                259                   259                                      
Other
                188                   188                   (539 )                 (539 )
                                                                                                 
Net cash provided by (used in) investing activities
    23,000             (18,441 )     537       (23,537 )     (18,441 )     5,975             (19,451 )     928       (6,903 )     (19,451 )
                                                                                                 
Cash Flows From Financing Activities:
                                                                                               
Proceeds from long-term debt
    35,000                               35,000       50,000                               50,000  
Repayments of long-term debt
    (170,000 )                             (170,000 )     (14,286 )                             (14,286 )
Distributions to unitholders
    (31,457 )                             (31,457 )     (31,057 )                             (31,057 )
Equity offering of common units
    164,786                               164,786                                      
Equity offering of common units-offering costs
    (272 )                             (272 )                                    
Contributions from parent
                                                    25             (25 )      
Distributions to parent
                (23,000 )             23,000                         (6,000 )           6,000        
Other
    676                   435       (435 )     676       10             (5 )     632       (632 )     5  
                                                                                                 
Net cash (used in) provided by financing activities
    (1,267 )           (23,000 )     435       22,565       (1,267 )     4,667             (5,980 )     632       5,343       4,662  
                                                                                                 
Net (decrease) increase in cash and cash equivalents
    9,193             263       6,737       (6,737 )     9,456       19,309             1,300       6,931       (6,931 )     20,609  
Cash and cash equivalents, beginning of year
    3,861       (1 )     40,832       59,896       (59,896 )     44,692       20,417           $ 43,267     $ 30,212     $ (30,212 )   $ 63,684  
                                                                                                 
Cash and cash equivalents, end of year
  $ 13,054     $ (1 )   $ 41,095     $ 66,633     $ (66,633 )   $ 54,148     $ 39,726     $     $ 44,567     $ 37,143     $ (37,143 )   $ 84,293  
                                                                                                 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 6 — Members’ Capital and Distributions
 
Common Units
 
In March 2010, we issued 7,446,250 common units in an underwritten public offering (including units issued upon the underwriters’ exercise of their option to purchase additional units). We used the net proceeds from the offering to repay a portion of the outstanding indebtedness under our Credit Facility, and we expect to use the increased borrowing capacity as needed for capital projects, acquisitions, hedging, working capital and general corporate purposes.
 
Class D Units
 
Class D units totaling 3,245,817 as of December 31, 2009 converted into our common units on a one-for-one basis in February 2010.
 
Distributions
 
The following table summarizes our quarterly cash distributions during 2010:
 
                     
    Distribution
               
Quarter Ending   Per Unit   Date Declared   Record Date   Payment Date   Amount
 
December 31, 2009
  $0.5750   January 13, 2010   February 1, 2010   February 11, 2010   $31,911,000
March 31, 2010
  $0.5750   April 14, 2010   April 30, 2010   May 13, 2010   $38,134,000
 
Accounting for Equity-Based Compensation
 
We use ASC 718 to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”). As of March 31, 2010, the number of units available for grant under our LTIP totaled 1,676,190, of which up to 1,075,497 units were eligible to be issued as restricted common units, phantom units or unit awards.
 
Equity Awards.  We recognized non-cash compensation expense of $1,808,000 and $1,711,000 related to the amortization of equity-based compensation under our LTIP during the three months ended March 31, 2010 and 2009, respectively. See Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2009 for details on our equity-based compensation.
 
Liability Awards.  During the three months ended March 31, 2010, we issued 56,223 common units to settle our fourth quarter 2009 Employee Incentive Compensation Program (“EICP”) and 2009 Management Incentive Compensation Plan (“MICP”) obligations.
 
Since ASC 480, “Accounting for Certain Financial Instruments With Characteristics of Both Liabilities and Equity,” requires unconditional obligations in the form of units that the issuer must or may settle by issuing a variable number of units to be classified as a liability, we classify equity awards issued to settle EICP and MICP obligations as liability awards. As of March 31, 2010, we accrued $606,000 and $326,000 for the first quarter 2010 EICP bonuses and an estimate of the 2010 MICP incentive bonuses, respectively. As of March 31, 2010, the estimated unrecognized compensation costs related to these liability awards totaled $1,819,000 and $1,196,000 for the EICP and MICP, respectively, which are expected to be recognized as expense on a straight-line basis through December 2010 for EICP awards and through February 2011 for MICP awards.
 
Note 7 — Net Income (Loss) Per Unit
 
Net income (loss) per unit is calculated in accordance with ASC 260, “Earnings Per Share.” ASC 260 specifies the use of the two-class method of computing earnings per unit when participating or multiple classes of securities


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 7 — Net Income (Loss) Per Unit (Continued)
 
exist. Under this method, undistributed earnings for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.
 
Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income (loss) per unit reflects potential dilution that could occur if convertible securities were converted into common units or contracts to issue common units were exercised except when the assumed conversion or exercise would have an anti-dilutive effect on net income (loss) per unit. Dilutive net income (loss) per unit is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.
 
Basic and diluted net (loss) income per common unit is calculated as follows:
 
                 
    Three Months Ended March 31,  
    2010     2009  
    (In thousands, except per unit information)  
 
Net (loss) income available — basic and diluted
  $ (1,260 )   $ 5,905  
                 
Basic weighted average units
    58,206       54,012  
Dilutive weighted average units(1)(2)
    58,206       57,814  
Basic net (loss) income per unit:
               
(Loss) income per unit from continuing operations
  $ (0.02 )   $ 0.10  
Income per unit from discontinued operations
          0.01  
                 
Net (loss) income per unit
  $ (0.02 )   $ 0.11  
                 
Diluted net (loss) income per unit:
               
(Loss) income per unit from continuing operations (1)(2)
  $ (0.02 )   $ 0.09  
Income per unit from discontinued operations (1)(2)
          0.01  
                 
Net (loss) income per unit
  $ (0.02 )   $ 0.10  
                 
 
 
(1) Our potentially dilutive common equity includes the following:
 
                 
    Three Months Ended
 
     March 31,  
    2010     2009  
    (In thousands)  
 
Employee options
          76  
Restricted units
          16  
Phantom units
          11  
Contingent incentive plan unit awards
          59  
Class C units
          395  
Class D units
          3,246  


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Table of Contents

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 7 — Net Income (Loss) Per Unit (Continued)
 
 
(2) The following potentially dilutive common equity was excluded from the dilutive net income (loss) per unit calculation because to include these equity securities would have been anti-dilutive:
 
                 
    Three Months Ended
 
    March 31,  
    2010     2009  
    (In thousands)  
 
Employee options
    1,246       1,339  
Unit appreciation rights
    318        
Restricted units
    105       149  
Phantom units
    697       576  
Class D units
    1,561        
Contingent incentive plan unit awards
    39        
 
Note 8 — Related Party Transactions
 
Natural Gas and Related Transactions
 
The following table summarizes transactions between us and affiliated entities (in thousands):
 
                 
    Three Months Ended March 31,  
    2010     2009  
 
Affiliates of Mr. Lawing:(1)
               
Natural gas sales(2)
  $ 1     $  
Gathering and compression services(3)
    2       6  
Natural gas purchases(4)
    281       350  
Reimbursable costs(5)
    75        
Reimbursements paid(6)
          638  
Payable by us as of March 31, 2010(7)
    63          
Webb Duval:
               
Natural gas sales(2)
          368  
Natural gas purchases(4)
    53       214  
Transportation costs(8)
    70       101  
Management fees(9)
    56       55  
Reimbursable costs(9)
    67       149  
Payable to us as of March 31, 2010(10)
    1,133          
Payable by us as of March 31, 2010(7)
    460          
Southern Dome:
               
Management fees(9)
    63       63  
Reimbursable costs(9)
    96       74  
Payable to us as of March 31, 2010(10)
    745          


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 8 —  Related Party Transactions (Continued)
 
                 
    Three Months Ended March 31,  
    2010     2009  
 
Bighorn:
               
Compressor rental fees(11)
    417        
Gathering costs(8)
    16       107  
Natural gas purchases(4)
    3        
Management fees(9)
    93       72  
Reimbursable costs(9)
    713       679  
Payable to us as of March 31, 2010(10)
    194          
Payable by us as of March 31, 2010(7)
    82          
Fort Union:
               
Gathering costs(8)
    1,371       2,009  
Treating costs(4)
    52       184  
Management fees(9)
    56       57  
Reimbursable costs(9)
    85       10  
Payable to us as of March 31, 2010(10)
    33          
Payable by us as of March 31, 2010(7)
    163          
Other:
               
Natural gas sales(2)
    60       38  
Payable to us as of March 31, 2010(10)
    36          
 
 
(1) These entities were controlled by John R. Eckel, Jr., our former Chairman and Chief Executive Officer, until his death in November 2009, and since that time have been controlled by Douglas L. Lawing, our Executive Vice President, General Counsel and Secretary.
 
(2) Revenues included in natural gas sales on our consolidated statements of operations.
 
(3) Revenues included in transportation, compression and processing fees on our consolidated statements of operations.
 
(4) Included in costs of natural gas and natural gas liquids on our consolidated statements of operations.
 
(5) Reimbursable costs received from Copano/Operations, Inc. (“Copano Operations”) for its use of shared personnel, facilities and equipment, which was the only compensation we received from Copano Operations.
 
(6) Reimbursable costs paid to Copano Operations for our use of shared personnel, office space, equipment, goods and services under an agreement that terminated on January 1, 2010. Effective January 1, 2010, we hired the personnel we share with Copano Operations, assumed responsibility for procuring the shared office space, equipment, goods and services and entered into a new agreement under which Copano Operations pays us for use of our shared personnel and other shared items.
 
(7) Included in accounts payable on the consolidated balance sheets.
 
(8) Costs included in transportation on our consolidated statements of operations.
 
(9) Management fees and reimbursable costs received from our unconsolidated affiliates consists of the total compensation paid to us by our unconsolidated affiliates and is included in general and administrative expenses on our consolidated statements of operations.
 
(10) Included in accounts receivable on the consolidated balance sheets.
 
(11) Revenues included in condensate and other on our consolidated statements of operations.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 8 — Related Party Transactions (Continued)
 
 
Our management believes that the terms and provisions of our related party agreements are fair to us; however, we cannot be certain that such agreements and services have terms as favorable to us as we could obtain from unaffiliated third parties.
 
Other Transactions
 
Certain of our operating subsidiaries and unconsolidated affiliates paid operating subsidiaries of Exterran Holdings, Inc. (“Exterran Holdings”) for the purchase and installation of compressors, compression services and compressor repairs. We paid Exterran Holdings $988,000 and $1,145,000 for the three months ended March 31, 2010 and 2009, respectively, for their services. Ernie L. Danner, a member of our Board of Directors, serves on the Board of Directors of Exterran Holdings and as its President and Chief Executive Officer. Our management believes that the terms and provisions of our related party agreements are fair to us; however, we cannot be certain that such agreements and services have terms as favorable to us as we could obtain from unaffiliated third parties.
 
Note 9 — Commitments and Contingencies
 
Commitments
 
For the three months ended March 31, 2010 and 2009, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $878,000 and $2,439,000, respectively.
 
We have both fixed and variable quantity contractual commitments arising in the ordinary course of our natural gas marketing activities. As of March 31, 2010, we had fixed contractual commitments to purchase 491,000 million British thermal units (“MMBtu”) of natural gas in April 2010. As of March 31, 2010, we had fixed contractual commitments to sell 2,228,000 MMBtu of natural gas in April 2010. All of these contracts are based on index-related market pricing. Using index-related market prices as of March 31, 2010, total commitments to purchase natural gas related to such agreements equaled $1,870,000 and total commitments to sell natural gas under such agreements equaled $8,529,000. Our commitments to purchase variable quantities of natural gas at index-based prices range from contract periods extending from one month to the life of the dedicated production. During March 2010, natural gas volumes purchased under such contracts equaled 10,806,000 MMBtu. Our commitments to sell variable quantities of natural gas at index-based prices range from contract periods extending from one month to the year 2012. During March 2010, natural gas volumes sold under such contracts equaled 4,865,000 MMBtu.
 
We are party to firm transportation agreements with Wyoming Interstate Gas Company (“WIC”), under which we are obligated to pay for transportation capacity whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $7,407,000 for the remainder of 2010, $9,876,000 in 2011, $9,867,000 in 2012, $8,978,000 in 2013, $5,509,000 in 2014 and $19,204,000 thereafter. The agreements expire on December 31, 2019. All of our obligations under these agreements are offset by capacity release agreements between us and third parties, under which they pay for the right to use our capacity. These capacity release agreements cover 100% of our total WIC capacity and continue through December 31, 2019. We have placed in escrow $1.9 million, classified as escrow cash on the consolidated balance sheets, as credit support for our obligations under the WIC agreements.
 
Additionally, we have two firm gathering agreements with Fort Union, under which we are obligated to pay for gathering capacity on the Fort Union system whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $3,637,000 for the remainder of 2010, $5,859,000 for 2011, $7,154,000 for 2012 and $7,665,000 for each of the years thereafter. Generally, we resell our firm capacity to third parties under various types of agreements. These commitments expire in November 30, 2017.
 
We have fixed-quantity contractual commitments to Targa North Texas LP (“Targa”) in settlement of a dispute regarding what portion, if any, of natural gas we purchase from producers that had been contractually dedicated for resale to Targa. As of March 31, 2010, we had fixed contractual commitments to provide Targa a total of 2,373,000


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Table of Contents

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 9 — Commitments and Contingencies (Continued)
 
thousand cubic feet (“Mcf”) of natural gas for October 1, 2009 through December 31, 2010 and for each of 2011, 2012 and 2013. As of March 31, 2010, we have accrued $754,136 of our obligation due December 31, 2010. Under the terms of the agreement, we are obligated to pay annual fees ($1.00 per Mcf, $1.10 per Mcf, $1.15 per Mcf and $1.25 per Mcf for 2010, 2011, 2012 and 2013, respectively) to the extent our natural gas deliveries to Targa fall below the committed quantity.
 
Regulatory Compliance
 
In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management, compliance with existing laws and regulations will not materially affect our financial position, results of operations or cash flows.
 
Litigation
 
As a result of our Cantera acquisition in October 2007, we acquired Cantera Gas Company LLC (“Cantera Gas Company,” formerly CMS Field Services, Inc. (“CMSFS”)). Cantera Gas Company is a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMSFS and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred before Cantera Resources, Inc. acquired CMSFS in June 2003 (the “CMS Acquisition”). The amount of liability, if any, against Cantera Gas Company is not reasonably estimable. Pursuant to the CMS Acquisition purchase agreement, CMS Gas Transmission has assumed responsibility for the defense of these claims, and Cantera Gas Company is fully indemnified by CMS Gas Transmission and its parent, CMS Enterprises Company, against any losses that Cantera Gas Company may suffer as a result of these claims.
 
We may, from time to time, be involved in other litigation and claims arising out of our operations in the normal course of business.
 
Note 10 — Supplemental Disclosures to the Statements of Cash Flows
 
                 
    Three Months Ended
 
    March 31,  
    2010     2009  
    (In thousands)  
 
Cash payments for interest, net of $495,000 and $1,163,000 capitalized in 2010 and 2009, respectively
  $ 14,966     $ 15,061  
Cash payments for federal and state income taxes
  $     $  
 
We incurred a change in liabilities for investing activities that had not been paid as of March 31, 2010 and 2009 of $2,407,000 and $7,711,000, respectively. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows. As of March 31, 2010 and 2009, we accrued $7,656,000 and $6,084,000, respectively, for capital expenditures that had not been paid and, therefore, these amounts are not included in investing activities for each respective period presented.
 
Note 11 — Financial Instruments
 
We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps and other financial instruments to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
Commodity Risk Hedging Program
 
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices as a result of: (i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling volumes of natural gas at index-related prices. In order to manage the risks associated with natural gas and NGL prices, we engage in risk management activities that take the form of commodity derivative instruments. These activities are governed by our risk management policy, which, subject to certain limitations, allows our management to purchase options and enter into swaps for crude oil, NGLs and natural gas in order to reduce our exposure to a substantial adverse change in the prices of those commodities. Our risk management policy prohibits the use of derivative instruments for speculative purposes.
 
Our Risk Management Committee monitors and ensures compliance with the risk management policy and consists of senior level executives in the operations, finance and legal departments. The Audit Committee of our Board of Directors monitors the implementation of the policy and we have engaged an independent firm to provide additional oversight. The risk management policy provides that all derivative transactions must be executed by our Chief Financial Officer and must be authorized in advance of execution by our Chief Executive Officer. The policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.
 
Financial instruments that we acquire pursuant to our risk management policy are generally designated as cash flow hedges under ASC 815 and are recorded on our consolidated balance sheets at fair value. For derivatives designated as cash flow hedges, we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and reclassify them to revenue within the consolidated statements of operations as the underlying transactions impact earnings. For derivatives not designated as cash flow hedges, we recognize changes in fair value as a gain or loss in our consolidated statements of operations. These financial instruments serve the same risk management purpose whether designated as a cash flow hedge or not.
 
We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in hedging the variability of forecasted cash flows of underlying hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying hedged item or it becomes probable that the original forecasted transaction will not occur, we discontinue hedge accounting and subsequent changes in the derivative fair value are immediately recognized as a gain or loss (increase or decrease in revenue) in our consolidated statements of operations.
 
As of March 31, 2010, we estimated that $2,344,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as a result of monthly physical settlements of crude oil, NGLs and natural gas.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
The following tables summarize our commodity hedge portfolio as of March 31, 2010 (all hedges are settled monthly):
 
Purchased Houston Ship Channel Index Natural Gas Options
 
                                         
    Call Spread     Call  
    Call Strike
                   
    (Per MMBtu)     Call Volumes
    Strike
       
    Bought     Sold     (MMBtu/d)     (Per MMBtu)     Volume (MMBtu/d)  
 
2010
  $ 7.3500     $ 10.0000       7,100     $ 10.0000       10,000  
2011
  $ 6.9500     $ 10.0000       7,100     $ 10.0000       10,000  
 
Purchased Houston Ship Channel Index Natural Gas Basis Swap
 
                 
    Price
    Volume
 
    (per MMBtu)     (MMBtu/d)  
 
2010(1)
  $ 0.0450       10,000  
 
 
(1) Instrument is not designated as a cash flow hedge under hedge accounting.
 
Sold CenterPoint East Index Natural Gas Basis Swap
 
                 
    Price
    Volume
 
    (per MMBtu)     (MMBtu/d)  
 
2010(1)
  $ 0.2300       10,000  
 
 
(1) Instrument is not designated as a cash flow hedge under hedge accounting.
 
Purchased Mt. Belvieu Purity Ethane Puts and Entered into Swaps
 
                                 
    Put     Swap  
    Strike
    Volumes
    Price
    Volumes
 
    (Per gallon)     (Bbls/d)     (Per gallon)     (Bbls/d)  
 
2010
  $ 0.5550       1,600     $ 0.5700       500  
2011
  $ 0.5300       1,700     $ 0.5450       500  
2011
  $ 0.5300       500              
2011
  $ 0.6200       500              
2012
  $ 0.5900       1,000              
 
Purchased Mt. Belvieu TET Propane Puts and Entered into Swaps
 
                                 
    Put     Swap  
    Strike
    Volumes
    Price
    Volumes
 
    (Per gallon)     (Bbls/d)     (Per gallon)     (Bbls/d)  
 
2010
  $ 0.8500       1,100              
2010
  $ 0.9460       700     $ 0.9925       700  
2011
  $ 0.8265       1,100              
2011
  $ 0.9340       700     $ 0.9750       700  
2011
  $ 1.3300       900              
2012
  $ 1.1500       700              


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
Purchased Mt. Belvieu TET Propane Put Spread Options
 
                         
    Put Spread  
    Strike
    Volumes
 
    (Per gallon)     (Bbls/d)  
    Bought     Sold        
 
2010
  $ 1.4900     $ 0.8500       1,100  
2010
  $ 1.4900     $ 0.9460       700  
 
Purchased Mt. Belvieu Non-TET Isobutane Puts and Entered into Swaps
 
                                 
    Put     Swap  
    Strike
    Volumes
    Price
    Volumes
 
    (Per gallon)     (Bbls/d)     (Per gallon)     (Bbls/d)  
 
2010
  $ 1.0350       300              
2010
  $ 1.1145       100     $ 1.2025       100  
2011
  $ 1.0205       300              
2011
  $ 1.1100       100     $ 1.1800       100  
2011
  $ 1.7100       200              
2012
  $ 1.3900       300              
 
Purchased Mt. Belvieu Non-TET Isobutane Put Spread Options
 
                         
    Put Spread  
    Strike
       
    (Per gallon)     Volumes
 
    Bought     Sold     (Bbls/d)  
 
2010
  $ 1.8900     $ 1.1145       100  
2010
  $ 1.8900     $ 1.0350       300  
 
Purchased Mt. Belvieu Non-TET Normal Butane Puts and Entered into Swaps
 
                                 
    Put     Swap  
    Strike
    Volumes
    Price
    Volumes
 
    (Per gallon)     (Bbls/d)     (Per gallon)     (Bbls/d)  
 
2010
  $ 1.0300       300              
2010
  $ 1.1000       200     $ 1.1850       200  
2011
  $ 1.0205       300              
2011
  $ 1.0850       200     $ 1.1700       200  
2011
  $ 1.7100       350              
2012
  $ 1.3600       350              
 
Purchased Mt. Belvieu Non-TET Normal Butane Put Spread Options
 
                         
    Put Spread  
    Strike
    Volumes
 
    (Per gallon)     (Bbls/d)  
    Bought     Sold        
 
2010
  $ 1.8800     $ 1.1000       200  
2010
  $ 1.8800     $ 1.0300       300  


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
Purchased Mt. Belvieu Non-TET Natural Gasoline Puts
 
                 
    Put  
    Strike
    Volumes
 
    (Per gallon)     (Bbls/d)  
 
2010
  $ 1.4080       300  
2011
  $ 1.4100       300  
 
Purchased Mt. Belvieu Non-TET Natural Gasoline Put Spread Options
 
                         
    Put Spread  
    Strike
    Volumes
 
    (Per gallon)     (Bbls/d)  
    Bought     Sold        
 
2010
  $ 2.5400     $ 1.4080       300  
 
Purchased WTI Crude Oil Puts
 
                 
    Put  
    Strike
    Volumes
 
    (Per barrel)     (Bbls/d)  
 
2010
  $ 55.00       1,000  
2010
  $ 60.00       400  
2011(1)
  $ 55.00       1,000  
2011
  $ 60.00       400  
2011
  $ 77.00       700  
2011
  $ 79.00       400  
2011(2)
  $ 85.00       200  
2012
  $ 79.00       300  
2012(2)
  $ 83.00       350  
2012(2)
  $ 85.00       350  
 
 
(1) Instrument is not designated as a cash flow hedge under hedge accounting.
 
(2) Instrument purchased April 2010.
 
Purchased WTI Crude Oil Put Spread Options
 
                         
    Put Spread  
    Strike
       
    (Per barrel)     Volumes
 
    Bought     Sold     (Bbls/d)  
 
2010
  $ 118.00     $ 55.00       1,000  
2010
  $ 118.00     $ 60.00       400  
 
Interest Rate Risk Hedging Program
 
Our interest rate exposure results from variable rate borrowings under our Credit Facility. We manage a portion of our interest rate exposure using interest rate swaps, which allow us to convert a portion of our variable rate debt into fixed rate debt. As of March 31, 2010, we hold a notional amount of $145.0 million in interest rate swaps with


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
an average fixed rate of 4.44% that mature between July 2010 and October 2012. As of March 31, 2010, our interest rate swaps are not designated as cash flow hedges.
 
As of March 31, 2010, we estimate that $442,000 of OCI will be reclassified as an increase to earnings in the next 12 months as the underlying instruments expire.
 
ASC 820 Fair Value Measurement and ASC 815 Disclosures about Derivative Instruments and Hedging Activities
 
We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. The three levels of the fair value hierarchy established by ASC 820 are as follows:
 
  •  Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
 
  •  Level 2 — Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and
 
  •  Level 3 — Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
 
At each balance sheet date, we perform an analysis of all instruments subject to ASC 820 and include in Level 3 all of those for which fair value is based on significant unobservable inputs.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010 and December 31, 2009. As required by ASC 820, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement with the fair value hierarchy levels.
 
                                 
    Fair Value Measurements on Hedging Instruments(a)
 
    March 31, 2010  
    Level 1     Level 2     Level 3     Total  
    (In thousands)  
 
Assets:
                               
Natural Gas:
                               
Short-term — Designated(b)
  $     $     $ 196     $ 196  
Long-term — Designated(c)
                526       526  
Natural Gas Liquids:
                               
Short-term — Designated(b)
                16,724       16,724  
Long-term — Designated(c)
                13,252       13,252  
Crude Oil:
                               
Short-term — Designated(b)
                13,414       13,414  
Long-term — Designated(c)
                3,123       3,123  
Long-term — Not designated(c)
                266       266  
                                 
Total
  $     $     $ 47,501     $ 47,501  
                                 
Liabilities:
                               
Natural Gas:
                               
Short-term — Not designated(d)
  $     $ 156     $     $ 156  
Natural Gas Liquids:
                               
Short-term — Designated(d)
                2,898       2,898  
Long-term — Designated(e)
                1,580       1,580  
Interest Rate:
                               
Short-term — Not designated(d)
          4,370             4,370  
Long-term — Not designated(e)
          3,722             3,722  
                                 
Total
  $     $ 8,248     $ 4,478     $ 12,726  
                                 
Total designated assets
  $     $     $ 42,757     $ 42,757  
                                 
Total not designated (liabilities)/assets
  $     $ (8,248 )   $ 266     $ (7,982 )
                                 
 
 
(a) Instruments re-measured on a recurring basis.
 
(b) Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”
 
(c) Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”
 
(d) Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”
 
(e) Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”
 


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
                                 
    Fair Value Measurements on Hedging Instruments(a)
 
    December 31, 2009  
    Level 1     Level 2     Level 3     Total  
    (In thousands)  
 
Assets
                               
Commodity derivatives:
                               
Short-term — Designated(b)
  $     $     $ 36,588     $ 36,588  
Short-term — Not designated(b)
          27             27  
Long-term — Designated(c)
                14,805       14,805  
Long-term — Not designated(c)
                576       576  
                                 
Total
  $     $ 27     $ 51,969     $ 51,996  
                                 
Liabilities
                               
Commodity derivatives:
                               
Short-term — Designated(d)
  $     $     $ 4,763     $ 4,763  
Long-term — Designated(e)
                4,600       4,600  
Interest rate derivatives:
                               
Short-term — Not designated(d)
          4,909             4,909  
Long-term — Not designated(e)
          3,238             3,238  
                                 
Total
  $     $ 8,147     $ 9,363     $ 17,510  
                                 
Total designated assets
  $     $     $ 42,030     $ 42,030  
                                 
Total not designated (liabilities)/assets
  $     $ (8,120 )   $ 576     $ (7,544 )
                                 
 
 
(a) Instruments re-measured on a recurring basis.
 
(b) Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”
 
(c) Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”
 
(d) Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”
 
(e) Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”
 
We use the income approach incorporating market-based inputs in determining fair value for our derivative contracts.
 
Valuation of our Level 2 derivative contracts are based on observable market prices (1-month or 3-month LIBOR interest rate curves or CenterPoint East and Houston Ship Channel market curves) incorporating discount rates and credit risk.
 
Valuation of our Level 3 derivative contracts incorporates the use of valuation models using significant unobservable inputs. To the extent certain model inputs are observable (prices of WTI Crude, Mt. Belvieu NGLs and Houston Ship Channel natural gas), we include observable market price and volatility data as inputs to our valuation model in addition to incorporating discount rates and credit risk. For those input parameters that are not readily available (implied volatilities for Mt. Belvieu NGL prices or prices for illiquid periods of price curves), the modeling methodology incorporates available market information to generate these inputs through techniques such as regression based extrapolation.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
The following table provides a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy (in thousands):
 
                                 
    Three Months Ended March 31, 2010  
    Natural Gas     Natural Gas Liquids     Crude Oil     Total  
    (In thousands)  
 
Assets balance, beginning of period
  $ 2,752     $ 15,641     $ 24,213     $ 42,606  
Total gains or losses:
                               
Non-cash amortization of option premium
    (1,456 )     (4,057 )     (2,465 )     (7,978 )
Other amounts included in earnings
          2,066       4,720       6,786  
Included in accumulated other comprehensive loss
    (572 )     6,583       (4,723 )     1,288  
Purchases
          7,381             7,381  
Settlements
          (2,116 )     (4,940 )     (7,056 )
Transfers in and/or out of Level 3
                       
                                 
Asset balance, end of year
  $ 724     $ 25,498     $ 16,805     $ 43,027  
                                 
Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the period
  $     $ (56 )   $ (438 )   $ (494 )
                                 
 
         
    Three Months Ended
 
    March 31, 2009  
    (In thousands)  
 
Assets balance, beginning of year
  $ 152,677  
Total gains or losses:
       
Non-cash amortization of option premium
    (9,188 )
Other amounts included in earnings
    25,285  
Included in accumulated other comprehensive loss
    (7,502 )
Purchases
     
Settlements
    (25,120 )
Transfers in and/or out of Level 3
     
         
Asset balance, end of year
  $ 136,152  
         
Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the year
  $ 56  
         
 
Unrealized and realized gains and losses for Level 3 recurring items recorded in earnings are included in revenue on the consolidated statements of operations. The effective portion of unrealized gains and losses relating to cash flow hedges are included in accumulated other comprehensive loss on the consolidated balance sheet and statement of members’ capital and comprehensive loss.
 
Transfers in and/or out of Level 2 or Level 3 represent existing assets or liabilities where inputs to the valuation became less observable or assets and liabilities that were previously classified as a lower level for which the lowest significant input became observable during the period. There were no transfers in or out of Level 2 or Level 3 during the period.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
We have not entered into any derivative transactions containing credit risk related contingent features as of March 31, 2010.
 
The following table presents derivatives that are designated as cash flow hedges:
 
The Effect of Derivative Instruments on the Statements of Operations
(In thousands)
 
                             
                Amount of Gain
     
                (Loss) Recognized
     
                in Income on
     
                Derivative
     
    Amount of Gain
    Amount of Gain
    (Ineffective
     
Derivatives in ASC
  (Loss) Recognized
    (Loss) Reclassified
    Portion and Amount
     
815 Cash Flow
  in OCI on
    from Accumulated
    Excluded from
     
Hedging
  Derivatives
    OCI into Income
    Effectiveness
    Statements of Operations
Relationships
  (Effective Portion)     (Effective Portion)     Testing)     Location
 
Three Months Ended March 31, 2010
Natural gas
  $ (2,013 )   $ (1,439 )   $     Natural gas sales
Natural gas liquids
    4,930       (1,654 )     (56 )   Natural gas liquids sales
Crude oil
    (2,351 )     2,370       25     Condensate and other
Interest rate swaps
          (132 )         Interest and other financing costs
                             
Total
  $ 566     $ (855 )   $ (31 )    
                             
Three Months Ended March 31, 2009
Natural gas
  $ 255     $ (766 )   $     Natural gas sales
Natural gas liquids
    (3,534 )     11,494       (16 )   Natural gas liquids sales
Crude oil
    (4,223 )     4,049       123     Condensate and other
Interest rate swaps
    (181 )     (81 )         Interest and other financing costs
                             
Total
  $ (7,683 )   $ 14,696     $ 107      
                             


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 11 — Financial Instruments (Continued)
 
The following table presents derivatives that are not designated as cash flow hedges:
 
The Effect of Derivative Instruments on the Statements of Operations
(In thousands)
 
             
Derivatives Not Designated as
  Amount of Gain
     
Hedging Instruments
  (Loss) Recognized
    Statement of Operations
Under ASC 820
  in Income on Derivative     Location
 
Three months ended March 31, 2010
Natural gas
  $ (227 )   Natural gas sales
Crude oil
    (306 )   Condensate and other
Interest rate swaps
    (1,466 )   Interest and other financing costs
             
Total
  $ (1,999 )    
             
Three months ended March 31, 2009
Natural gas liquids
  $ 56     Natural gas liquids sales
Interest rate swaps
    75     Interest and other financing costs
             
Total
  $ 131      
             
 
Note 12 — Fair Value of Financial Instruments
 
Amounts reflected in our consolidated balance sheets as of March 31, 2010 for cash and cash equivalents approximate fair value. The fair value of our Credit Facility has been estimated based on similar debt transactions that occurred during the three months ended March 31, 2010. Estimates of the fair value of our Senior Notes are based on market information as of March 31, 2010. A summary of the fair value and carrying value of the financial instruments is shown in the table below.
 
                 
    March 31, 2010  
    Carrying
    Estimated
 
    Value     Fair Value  
    (In thousands)  
 
Cash and cash equivalents
  $ 54,148     $ 54,148  
Credit Facility
    135,000       131,971  
2016 Notes
    332,665       337,655  
2018 Notes
    249,525       249,525  


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 13 — Discontinued Operations
 
Effective October 1, 2009, we sold our crude oil pipeline and related assets, and as a result, we have classified the results of operations and financial position of our crude oil pipeline as “discontinued operations” for all periods presented. In the fourth quarter of 2009, we recognized a gain on the sale of the crude oil pipeline system of approximately $0.9 million. Selected financial data for the crude oil pipeline and related assets are as follows (in thousands):
 
                 
    Three Months Ended
 
    March 31,  
    2010     2009  
 
Crude oil sales
  $     $ 15,338  
Cost of crude oil purchases
          14,428  
Income from discontinued operations before taxes
  $     $ 561  
Income tax expense
           
                 
Net income from discontinued operations
  $     $ 561  
                 
 
Note 14 — Segment Information
 
We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into the following three segments for both internal and external reporting and analysis:
 
  •  Oklahoma, which includes midstream natural gas services in central and east Oklahoma, including 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 and, through September 30, 2009, included a crude oil pipeline.
 
  •  Texas, which includes 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. Our Texas segment includes our Louisiana processing assets and our equity investment in Webb Duval.
 
  •  Rocky Mountains, which includes natural gas gathering and treating and compressor rental services in Wyoming. Our Rocky Mountains segment includes our equity investments in Bighorn and Fort Union.
 
The amounts indicated below 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 reporting segments.
 
We evaluate segment performance based on segment gross margin before depreciation, amortization and impairment. All of our revenue is derived from, and all of our assets and operations are located in Oklahoma, Texas, Wyoming and Louisiana in the United States. Operating and maintenance expenses and general and administrative expenses incurred at corporate and other are allocated to Oklahoma, Texas and Rocky Mountains based on actual expenses directly attributable to each segment or an allocation based on activity, as appropriate. We use the same accounting methods and allocations in the preparation of our segment information as we use in our consolidated reporting.


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COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note 14 — Segment Information (Continued)
 
Summarized financial information concerning our reportable segments is shown in the following table (in thousands). Prior year information has been restated to conform to the current year presentation of our segment information.
 
                                                 
                Rocky
    Total
    Corporate
       
    Oklahoma(a)     Texas     Mountains     Segments     and Other     Consolidated  
 
Three Months Ended March 31, 2010:
                                               
Total segment gross margin
  $ 24,275     $ 27,165     $ 1,103     $ 52,543     $ (1,418 )   $ 51,125  
Operations and maintenance expenses
    5,433       6,569       101       12,103             12,103  
Depreciation and amortization
    8,415       5,585       766       14,766       435       15,201  
General and administrative expenses
    2,287       2,410       537       5,234       5,308       10,542  
Taxes other than income
    499       663             1,162             1,162  
Equity in (earnings) loss from unconsolidated affiliates
    (954 )     65       (906 )     (1,795 )           (1,795 )
                                                 
Operating income (loss)
  $ 8,595     $ 11,873     $ 605     $ 21,073     $ (7,161 )   $ 13,912  
                                                 
Natural gas sales
  $ 59,481     $ 61,811     $ 604     $ 121,896     $ (1,680 )   $ 120,216  
Natural gas liquids sales
    61,023       60,286             121,309       (1,991 )     119,318  
Transportation, compression and processing fees
    1,243       7,337       4,534       13,114             13,114  
Condensate and other
    8,956       2,392       417       11,765       2,253       14,018  
                                                 
Sales to external customers
  $ 130,703     $ 131,826     $ 5,555     $ 268,084     $ (1,418 )   $ 266,666  
                                                 
Intersegment sales
  $     $     $     $     $     $  
Interest and other financing costs
  $     $     $     $     $ 14,945     $ 14,945  
Segment assets
  $ 719,306     $ 453,612     $ 686,564     $ 1,859,482     $ 10,616     $ 1,870,098  
Three Months Ended March 31, 2009:
                                               
Total segment gross margin
  $ 14,300     $ 20,580     $ 799     $ 35,679     $ 16,096     $ 51,775  
Operations and maintenance expenses
    5,616       7,054       2       12,672             12,672  
Depreciation and amortization
    7,754       4,347       671       12,772       333       13,105  
General and administrative expenses
    1,971       2,251       749       4,971       5,754       10,725  
Taxes other than income
    404       380       2       786             786  
Equity in (earnings) loss from unconsolidated affiliates
    (217 )     24       (1,291 )     (1,484 )           (1,484 )
                                                 
Operating (loss) income
  $ (1,228 )   $ 6,524     $ 666     $ 5,962     $ 10,009     $ 15,971  
                                                 
Natural gas sales
  $ 40,868     $ 51,754     $ 2,737     $ 95,359     $ (380 )   $ 94,979  
Natural gas liquids sales
    33,066       36,180             69,246       11,585       80,831  
Transportation, compression and processing fees
    1,787       7,595       5,617       14,999             14,999  
Condensate and other
    4,549       829             5,378       4,891       10,269  
                                                 
Sales to external customers
  $ 80,270     $ 96,358     $ 8,354     $ 184,982     $ 16,096     $ 201,078  
                                                 
Intersegment sales
  $ (290 )   $ 290     $     $     $     $  
Interest and other financing costs
  $     $     $     $     $ 14,448     $ 14,448  
 
 
(a) All information excludes the results of discontinued operations for the sale of the crude oil pipeline and related assets (Note 13) except for the information related to intersegment sales and interest and other financing costs.


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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
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 in Item 1 of this report, as well as Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the audited financial statements included in Item 8 of our Annual Report on Form 10-K and Amendment No. 1 for the year ended December 31, 2009 (our “2009 10-K”).
 
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
 
Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. 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 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.
 
  •  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 and compressor rental services. 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.
 
Recent Developments
 
Commencement of fractionation activities.  In April 2010, we started our fractionator at the Houston Central plant, which adds approximately 22,000 barrels per day of fractionation capacity to the gulf coast region and helps to offset the effects of limited fractionation capacity on our Texas segment. We will deliver purity propane and purity ethane under new long-term contracts with Dow Hydrocarbons and Resources via pipelines we own or lease, and we will sell the remaining purity products via new truck racks installed at the Houston Central plant.


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Expanded commodity risk management portfolio.  We purchased puts for ethane (calendar 2011 and 2012), propane (calendar 2012), normal-butane (calendar 2012), crude oil (calendar 2011 and 2012) and iso-butane (calendar 2012) at strike prices reflecting current market conditions. We purchased these options from investment grade counterparties in accordance with our risk management policy and designated them as cash flow hedges to mitigate the impact of decreases in NGL and crude oil prices. Our net costs for these transactions were approximately $10.8 million.
 
Declaration of distribution.  On April 14, 2010, our Board of Directors declared a cash distribution of $0.575 per common unit for the first quarter of 2010. This distribution will be paid on May 13, 2010 to all common unitholders of record at the close of business on April 30, 2010.
 
Common unit offering.  In March 2010, we issued 7,446,250 common units at an offering price of $23.10 per unit. We used the net proceeds from the offering to repay a portion of the outstanding indebtedness under our revolving credit facility, and we expect to use the increased borrowing capacity as needed for capital projects, acquisitions, hedging, working capital and general corporate purposes.
 
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 and in Item 7 of our 2009 10-K. 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. 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 act as a disincentive to producers, particularly when combined with high operating costs or high third-party transportation costs. Producers typically increase new drilling activity when natural gas prices are sufficient to make drilling and production economic and, depending on the severity and duration of an unfavorable pricing environment, producers may suspend drilling and completion activity to the degree they have become uneconomic.
 
The level at which drilling and production become economic depends on natural gas prices and a variety of other factors. Other factors include the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir, among other things, and the extent to which the producer relies on commodity price hedging. In addition, producers may drill when they otherwise would not if drilling activity is necessary to maintain their leasehold interests. 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 NGLs increase. Improving crude oil prices could also lead to increased production of casinghead natural gas associated with oil production.
 
First-Quarter Commodity Prices.  Crude oil prices have continued the recovery that began in early 2009. While natural gas and NGL prices remain stronger compared to 2009 lows, both have declined consistently since January 2010. Because natural gas and NGL prices reached near-term highs in January 2010, first-quarter averages for both are higher than fourth-quarter 2009 averages despite declines in both for much of the first quarter. Forward pricing on NYMEX reflects market expectations that crude oil prices in the coming months will be modestly higher compared to recent months and that natural gas will stabilize in the range of the prices realized in recent months. NGL forward-pricing curves indicate expectations that NGL prices will also stabilize.


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We believe that natural gas prices are influenced by regional drilling activity, takeaway capacity, the severity of winter and summer weather (and other factors that influence consumption and demand), natural gas storage levels, liquefied natural gas imports (and other competing supplies of natural gas), NGL transportation and fractionation capacity and the overall economy. 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 declines in natural gas and NGL prices and reduced drilling activity.
 
Pricing Trends in Texas.  After improving significantly in late 2009, natural gas and NGL prices in Texas began the year at 12-month highs and declined through the first quarter of 2010 and the second quarter of 2010 to date. First-of-the-month prices for natural gas on the Houston Ship Channel index were $3.92 per MMBtu for April 2010 and $4.15 per MMBtu for May 2010, and weighted-average daily prices for NGLs at Mt. Belvieu through May 3, 2010, based on our first-quarter 2010 product mix, were $45.58 per barrel.
 
The following graph and table summarize prices for crude oil on NYMEX and for natural gas and NGLs on the primary indices we use for Texas pricing.
 
Texas Prices for Crude Oil, Natural Gas and NGLs(1)
 
(LINE GRAPH)
 
(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average quarterly NGL prices are calculated based on our weighted-average product mix at Mt. Belvieu for the period indicated.
 
                                           
    Quarterly Data for Texas:  
    Q1 2009     Q2 2009     Q3 2009     Q4 2009       Q1 2010  
Houston Ship Channel ($/MMBtu)
  $ 4.21     $ 3.44     $ 3.32     $ 4.16       $ 5.36  
Mt. Belvieu ($/barrel)
  $ 25.81     $ 30.12     $ 35.09     $ 42.96       $ 47.66  
NYMEX crude oil ($/barrel)
  $ 43.31     $ 59.79     $ 68.24     $ 76.13       $ 78.72  
Service throughput (MMBtu/d)
    644,752       630,674       613,234       576,224         582,958  
Plant inlet (MMBtu/d)
    558,115       559,597       543,994       497,368         457,233  
NGLs produced (Bbls/d)
    16,878       18,425       18,197       18,292         15,339  
Segment gross margin (in thousands)
  $ 20,580     $ 23,320     $ 26,875     $ 32,845       $ 27,165  
 
Pricing Trends in Oklahoma.  After improving significantly in late 2009, natural gas and NGL prices in Oklahoma began 2010 at 18-month highs and declined through the first quarter of 2010 and the second quarter 2010 to date. First-of-the-month prices for natural gas on the CenterPoint East index were $3.70 per MMBtu for April


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2010 and $3.97 per MMBtu for May 2010, and weighted-average daily prices for NGLs at Conway through May 3, 2010, based on our first quarter product mix, were $39.08 per barrel.
 
The following graph and table summarize prices for crude oil on NYMEX and for natural gas and NGLs on the primary indices we use for Oklahoma pricing.
 
Oklahoma Prices for Crude Oil, Natural Gas and NGLs(1)
 
(LINE GRAPH)
 
(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average quarterly NGL prices are calculated based on our weighted-average product mix at Conway for the period indicated. Segment gross margin results exclude activities attributable to our crude oil pipeline and related assets discussed in Note 13, “Discontinued Operations,” to our unaudited consolidated financial statements included in Item 1 of this report.
 
                                           
    Quarterly Data for Oklahoma:  
    Q1 2009     Q2 2009     Q3 2009     Q4 2009       Q1 2010  
CenterPoint East ($/MMBtu)
  $ 3.37     $ 2.70     $ 2.98     $ 4.01       $ 5.22  
Conway ($/barrel)
  $ 24.13     $ 25.57     $ 27.62     $ 40.86       $ 44.44  
NYMEX crude oil ($/barrel)
  $ 43.31     $ 59.79     $ 68.24     $ 76.13       $ 78.72  
Service throughput (MMBtu/d)
    271,222       267,576       260,296       250,248         248,784  
Plant inlet (MMBtu/d)
    160,181       166,846       166,884       159,713         152,190  
NGLs produced (Bbls/d)
    15,309       15,981       16,474       16,123         15,334  
Segment gross margin (in thousands)
  $ 14,300     $ 17,472     $ 18,284     $ 26,628       $ 24,275  
 
Basis Trends.  Prices for the first quarter of 2010 reflected a widening of the average basis differential between Mt. Belvieu and Conway, which was $3.03 per barrel, as compared to $2.09 per barrel for the fourth quarter of 2009. Prices for purity ethane account for 52% of this basis differential. At May 3, 2010, this basis differential was $5.70 per barrel. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.14 per MMBtu for the first quarter, slightly narrowed from $0.15 per MMBtu for the fourth quarter of 2009, and was $0.18 per MMBtu for May 2010.
 
Pricing Trends in the Rocky Mountains.  After improving significantly in late 2009, Rocky Mountains natural gas prices declined in the first quarter of 2010 and the second quarter 2010 to date. First-of-the-month prices for natural gas on the Colorado Interstate Gas (“CIG”) index were $3.57 per MMBtu for April and $3.67 per MMBtu for May 2010.


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The following graph and table summarize prices for natural gas on CIG, the primary index we use for the Rocky Mountains.
 
Rocky Mountains Natural Gas Prices(1)
 
(LINE GRAPH)
 
(1) Natural gas prices are first-of-the-month index prices.
 
                                           
    Quarterly Data for Rocky Mountains:  
    Q1 2009     Q2 2009     Q3 2009     Q4 2009       Q1 2010  
-
                                         
CIG ($/MMBtu)
  $ 3.27     $ 2.36     $ 2.67     $ 3.96       $ 5.14  
Pipeline throughput (MMBtu/d)(1)
    1,005,998       980,694       952,126       965,033         931,319  
Segment gross margin (in thousands)(2)
  $ 799     $ 711     $ 634     $ 1,110       $ 1,103  
 
 
(1) Includes 100% of Bighorn and Fort Union.
 
(2) Excludes results and volumes associated with our equity interests in Bighorn and Fort Union.
 
First Quarter Drilling and Production Activity.  Drilling activity in lean gas areas generally has remained low due to weaker natural gas prices and has improved in rich gas areas, where crude oil and NGL production have supported natural gas drilling economics. Changes in drilling activity are reflected in our throughput volumes only gradually because of the time required to drill, complete and attach new wells or, when drilling is declining, because of continuing production from already-completed wells. Therefore, our volumes continue to show the negative effects of last year’s sharp declines in drilling and do not fully reflect the positive effects of recent improvements in rich gas drilling activity.
 
Volume declines due to lower drilling activity in each of our operating segments contributed to our overall lower volumes compared to the first quarter of 2009. However, a decrease in low-margin gas from a third-party pipeline in Texas and a six-day shutdown of our Houston Central plant in preparation for start-up of our fractionator were also significant factors.
 
In Texas, declines in our lean gas volumes are significantly offset by increasing rich gas volumes, which is consistent with our belief that, generally, rich gas drilling will show more consistent improvement under the current market conditions. In Oklahoma, however, we have seen increasing activity and volumes in lean gas areas and relatively flat activity and volumes in rich gas areas. Based on our conversations with producers in the region, we


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believe that a significant amount of this activity is supported by commodity hedging or producers’ need to drill in order to maintain their leasehold interests or to recover costs they have already incurred.
 
While commodity prices and financial market conditions have improved compared to this time last year, prices continue to show some volatility, and drilling activity has been sporadic. It remains uncertain when producers will undertake sustained increases in drilling activity throughout the areas in which we operate. If the pricing environment of the first quarter of 2010 continues, we anticipate sustained or increasing drilling activity in areas that produce rich gas, for example the Eagle Ford Shale trend in south Texas and the Barnett Shale Combo play in north Texas, and a continued low level of drilling activity in most areas that produce lean gas, for example 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, although other factors such as commodity hedges or the need to maintain leasehold interests will also influence their decisions. Forward pricing suggests that NGL prices will improve modestly in the near future and that natural gas prices will stabilize; however, forward curves only reflect market expectations, and it is uncertain to what extent they will influence producers’ drilling decisions. In addition, as noted above, once drilling activity increases, a recovery in volumes will be subject to delays ranging from three months to as long as 18 months, depending on the characteristics of the reservoir, for processes involved in completing and attaching new wells.
 
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 higher fractionation costs. If NGL fractionation capacity remains constrained, these higher costs could offset the benefits of improving NGL prices to some extent. In April 2010, we started our fractionator at the Houston Central plant, which we believe will allow us to benefit from fractionation demand rather than operating subject to capacity constraints that expose us to higher fractionation costs.
 
Factors Affecting Operating Results and Financial Condition
 
Our first-quarter 2010 results reflect the effects on our volumes of limited drilling that followed 2009’s weaker pricing environment, and the interruption of operations at our Houston Central plant to perform maintenance, complete the connection for ethane and propane lines and to prepare for the start-up of our fractionator. Our results also are beginning to reflect the offsetting effect of rich gas drilling that has followed improvement in NGL prices. Relatively strong NGL prices in Oklahoma and Texas combined with lower natural gas prices in Texas during the first quarter of 2010 have continued to benefit our processing margins. Our combined operating segment gross margins increased 47% compared to the first 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 much of 2009, cash settlements from our commodity hedge portfolio helped to offset the decline in operating revenues attributable to lower commodity prices. For the first quarter of 2010, improvements in commodity prices have increased our operating segment cash flow and reduced our cash flow from commodity hedge settlements. For the first quarter of 2010, we received $7.0 million in net cash settlements from our commodity hedge portfolio, compared to $25.1 million for the first quarter of 2009.
 
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.
 
For additional discussion of each of these measures, see “— How We Evaluate Our Operations” under Item 7 of our 2009 10-K.


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Reconciliation of Non-GAAP Financial Measures.  The following table presents a reconciliation of the non-GAAP financial measures of (i) total segment gross margin (which consists of the sum of individual segment gross margins and the results of our risk management activities, which are included in corporate and other) to the GAAP financial measure of operating income, (ii) EBITDA and adjusted EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income (loss), for each of the periods indicated.
 
                 
    Three Months Ended March 31,  
    2010     2009  
    (In thousands)  
 
Reconciliation of total segment gross margin to operating income:
               
Operating income
  $ 13,912     $ 15,971  
Add: Operations and maintenance expenses
    12,103       12,672  
Depreciation and amortization
    15,201       13,105  
General and administrative expenses
    10,542       10,725  
Taxes other than income
    1,162       786  
Equity in earnings from unconsolidated affiliates
    (1,795 )     (1,484 )
                 
Total segment gross margin
  $ 51,125     $ 51,775  
                 
Reconciliation of EBITDA and adjusted EBITDA to net (loss) income:
               
Net (loss) income
  $ (1,260 )   $ 5,905  
Add: Depreciation and amortization(1)
    15,201       13,165  
Interest and other financing costs
    14,945       14,448  
Provision for income taxes
    234       164  
                 
EBITDA
    29,120       33,682  
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments
    4,645       4,818  
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates
    1,537       1,557  
Copano’s share of interest and other financing costs incurred by our equity method investments
    371       508  
                 
Adjusted EBITDA
  $ 35,673     $ 40,565  
                 
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
               
Cash flow provided by operating activities
  $ 29,164     $ 35,398  
Add: Cash paid for interest and other financing costs
    14,050       13,178  
Equity in earnings from unconsolidated affiliates
    1,795       1,484  
Distributions from unconsolidated affiliates
    (5,765 )     (5,371 )
Risk management activities
    (597 )     (9,188 )
Changes in working capital and other
    (9,527 )     (1,819 )
                 
EBITDA
    29,120       33,682  
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments
    4,645       4,818  
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates
    1,537       1,557  
Copano’s share of interest and other financing costs incurred by our equity method investments
    371       508  
                 
Adjusted EBITDA
  $ 35,673     $ 40,565  
                 


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    Three Months Ended March 31,  
    2010     2009  
    (In thousands)  
 
Reconciliation of net (loss) income to total distributable cash flow:
               
Net (loss) income
  $ (1,260 )   $ 5,905  
Add: Depreciation and amortization(1)
    15,201       13,165  
Amortization of commodity derivative options
    7,978       9,188  
Amortization of debt issue costs
    895       1,270  
Equity-based compensation
    2,715       1,959  
Distributions from unconsolidated affiliates
    6,737       6,931  
Unrealized loss associated with line fill contributions and gas imbalances
    1,582       166  
Unrealized loss (gain) on derivatives
    533       (239 )
Deferred taxes and other
    (301 )     346  
Less: Equity in earnings from unconsolidated affiliates
    (1,795 )     (1,484 )
Maintenance capital expenditures
    (1,431 )     (2,151 )
                 
Total distributable cash flow(2)
  $ 30,854     $ 35,056  
                 
 
 
(1) Includes activity related to our crude oil pipeline and related assets for the three months ended March 31, 2009, which are classified as discontinued operations as discussed in Note 13, “Discontinued Operations,” to our unaudited consolidated financial statements included in Item 1 of this report.
 
(2) Prior to any retained cash reserves established by our Board of Directors.
 
How We Manage Our Operations
 
Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models and standardized processing margin (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting and (iv) an imbalance monitoring and control system.
 
Our “standardized” processing margin is based on a fixed set of assumptions, with respect to NGL composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices, such as volumes, changes in NGL composition, recovery rates and variable contract terms. However, we believe this calculation is representative of the current operating commodity price environment of our Texas processing operations, and we use this calculation to track commodity price relationships. Our standardized processing margins averaged $0.5745 and $0.181 per gallon during the three months ended March 31, 2010 and 2009, respectively. The average standardized processing margin for the period from January 1, 1989 through March 31, 2010 is $0.1528 per gallon.
 
For a further discussion, please read Item 7 “— How We Manage Our Operations” under Item 7 of our 2009 10-K.
 
Forward-Looking Statements
 
This report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this report, including, but not limited to, those under “— Our Results of Operations” and “— Liquidity and Capital Resources” are forward-looking statements. Statements included in this report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements 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

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historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in these statements. Any differences could be caused by a number of factors, including, but not limited to:
 
  •  our ability to successfully integrate any acquired asset or operations;
 
  •  the volatility of prices and market demand for natural gas, crude oil and NGLs;
 
  •  our ability to continue to connect new sources of natural gas supply;
 
  •  our ability to access NGL fractionation capacity;
 
  •  the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;
 
  •  our ability to retain key customers and contract with new customers;
 
  •  the availability of local, intrastate and interstate transportation systems and other facilities for natural gas and NGLs;
 
  •  our ability to access our revolving credit facility and to obtain additional financing on acceptable terms;
 
  •  the effectiveness of our hedging program;
 
  •  general economic conditions;
 
  •  force majeure situations such as the loss of a market or facility downtime;
 
  •  the effects of government regulations and policies; and
 
  •  other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.
 
Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, including in conjunction with the forward-looking statements referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth under Item 1A, “Risk Factors” in Part II of this report and in our 2009 10-K. All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, 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.


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Our Results of Operations
 
                 
    Three Months Ended
 
    March 31,  
    2010     2009  
    ($ in thousands)  
 
Total segment gross margin(1)(2)
  $ 51,125     $ 51,775  
Operations and maintenance expenses(2)
    12,103       12,672  
Depreciation and amortization(2)
    15,201       13,105  
General and administrative expenses
    10,542       10,725  
Taxes other than income
    1,162       786  
Equity in earnings from unconsolidated affiliates(3)(4)(5)
    (1,795 )     (1,484 )
                 
Operating income(2)
    13,912       15,971  
Gain on retirement of unsecured debt
          3,939  
Interest and other financing costs, net
    (14,938 )     (14,402 )
Provision for income taxes
    (234 )     (164 )
Discontinued operations, net of tax
          561  
                 
Net (loss) income
  $ (1,260 )   $ 5,905  
                 
Total segment gross margin:(8)
               
Oklahoma(2)
  $ 24,275     $ 14,300  
Texas
    27,165       20,580  
Rocky Mountains(6)
    1,103       799  
                 
Segment gross margin(2)
    52,543       35,679  
Corporate and other(7)
    (1,418 )     16,096  
                 
Total segment gross margin(1)(2)
  $ 51,125     $ 51,775  
                 
Segment gross margin per unit:(8)
               
Oklahoma:
               
Service throughput ($/MMBtu)(2)
  $ 1.08     $ 0.59  
Texas:
               
Service throughput ($/MMBtu)
  $ 0.52     $ 0.35  
Volumes:(8)
               
Oklahoma:(9)
               
Service throughput (MMBtu/d)
    248,784       271,222  
Plant inlet volumes (MMBtu/d)
    152,190       160,181  
NGLs produced (Bbls/d)
    15,334       15,309  
Texas:(10)
               
Service throughput (MMBtu/d)
    582,958       644,752  
Pipeline throughput (MMBtu/d)
    316,937       304,158  
Plant inlet volumes (MMBtu/d)
    457,233       558,195  
NGLs produced (Bbls/d)
    15,339       16,878  
Capital expenditures
               
Maintenance capital expenditures
  $ 1,431     $ 2,151  
Expansion capital expenditures
    20,406       10,535  
                 
Total capital expenditures
  $ 21,837     $ 12,686  
                 
Operations and maintenance expenses:
               
Oklahoma(2)
  $ 5,433     $ 5,616  
Texas
    6,569       7,054  
Rocky Mountains
    101       2  
                 
Total operations and maintenance expenses(2)
  $ 12,103     $ 12,672  
                 
 
 
(1) Total segment gross margin is a non-GAAP financial measure. See “— How We Evaluate Our Operations” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
 
(2) Excludes results attributable to our crude oil pipeline and related assets for the three months ended March 31, 2009, which are classified as discontinued operations, as discussed in Note 13, “Discontinued Operations,” in our unaudited consolidated financial statements included in Item 1 of this report.


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(3) Includes results and volumes associated with our interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 931,319 MMBtu/d and 1,005,998 MMBtu/d for the three months ended March 31, 2010 and 2009, respectively.
 
(4) Includes results and volumes associated with our interest in Southern Dome. For the three months ended March 31, 2010, plant inlet volumes for Southern Dome averaged 14,130 MMBtu/d and NGLs produced averaged 499 Bbls/d. For the three months ended March 31, 2009, plant inlet volumes for Southern Dome averaged 10,608 MMBtu/d and NGLs produced averaged 367 Bbls/d.
 
(5) Includes results and volumes associated with our interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 60,091 MMBtu/d and 88,740 MMBtu/d for the three months ended March 31, 2010 and 2009, respectively.
 
(6) 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 WIC and compressor rental services provided to Bighorn. Excludes results and volumes associated with our interest in Bighorn and Fort Union.
 
(7) Corporate and other includes results attributable to our commodity risk management activities.
 
(8) “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 or gathered through our pipelines.
 
(9) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties. For the three months ended March 31, 2010, plant inlet volumes averaged 117,602 MMBtu/d and NGLs produced averaged 12,468 Bbls/d for plants owned by the Oklahoma segment. For the three months ended March 31, 2009, plant inlet volumes averaged 122,902 MMBtu/d and NGLs produced averaged 12,535 Bbls/d for plants owned by the Oklahoma segment. Excludes volumes associated with our interest in Southern Dome.
 
(10) Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 450,417 MMBtu/d and NGLs produced averaged 14,852 Bbls/d for the three months ended March 31, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 535,083 MMBtu/d and NGLs produced averaged 15,049 Bbls/d for the three months ended March 31, 2009 for plants owned by the Texas segment. Excludes volumes associated with our interest in Webb Duval.
 
Three Months Ended March 31, 2010 Compared To Three Months Ended March 31, 2009
 
Net loss totaled $1.3 million, or $0.02 per unit on a diluted basis for the three months ended March 31, 2010 compared to net income of $5.9 million, or $0.10 per unit on a diluted basis for the three months ended March 31, 2009. The drivers of the $7.2 million change from the first quarter of 2010 compared to the first quarter of 2009 primarily included:
 
  •  $3.9 million decrease in earnings related to the gain on the retirement of debt in the three months ended March 31, 2009;
 
  •  $2.1 million of additional depreciation and amortization expenses primarily related to expanded operations in north Texas and retirement of certain assets in Oklahoma;
 
  •  $0.7 million decrease in total segment gross margin consisting of a decrease of $17.5 million from our commodity risk management activities, offset by a $16.8 million increase in combined operating segment gross margins primarily reflecting a period-over-period increase in average NGL prices of 84% on the Conway index and 85% on the Mt. Belvieu index, slightly offset by lower overall service throughput volumes; and
 
  •  $0.5 million increase in interest and other financing costs primarily related to (i) an unrealized loss on interest rate swaps for 2010 of $0.1 million compared to a $0.1 million gain in 2009, a change of $0.2 million and (ii) an increase of $0.3 million in interest paid on interest rate swap arrangements.
 
Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $24.3 million for the three months ended March 31, 2010 compared to $14.3 million for the three months ended March 31, 2009, an increase of $10.0 million, or 70%. The increase in segment gross margin resulted primarily from period-over-period increases in average natural gas and NGL prices of 55% and 84%, respectively. The Oklahoma segment gross margin per unit of service throughput increased $0.49 per MMBtu to $1.08 per MMBtu for the three months ended March 31, 2010 compared to $0.59 per MMBtu for the three months ended March 31, 2009. The increase in segment gross margin was partially offset by decreases in service throughput and plant inlet volumes of 8% and 5%, respectively, however NGLs produced were flat. Please read “— Trends and Uncertainties — Market and Industry Trends.” The Oklahoma segment included our crude oil pipeline activities through September 30, 2009. The segment gross margin results above exclude $0.8 million related to our crude oil pipeline activities for the three months ended


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March 31, 2009. Please read “— Trends and Uncertainties — Market and Industry Trends and — Commodity Price and Producer Activity.”
 
Texas Segment Gross Margin.  Texas segment gross margin was $27.2 million for the three months ended March 31, 2010 compared to $20.6 million for the three months ended March 31, 2009, an increase of $6.6 million, or 32%. The Texas segment gross margin per unit of service throughput increased $0.17 per MMBtu to $0.52 per MMBtu for the three months ended March 31, 2010 compared to $0.35 per MMBtu for the three months ended March 31, 2009, primarily reflecting higher average NGL prices, which increased 85% period-over-period. The increase in segment gross margin was offset by a 10% decline in service throughput for the three months ended March 31, 2010 and higher average natural gas prices, which increased 27% compared to the three months ended March 31, 2009. The Texas segment gathered an average of 316,937 MMBtu/d of natural gas, processed an average of 457,233 MMBtu/d of natural gas at its plants and third-party plants and produced an average of 15,339 Bbls/d of NGLs at its plants and third-party plants during the first quarter of 2010, representing an increase of 4% in volumes gathered and decreases of 18% in volumes processed and 9% in NGLs produced as compared to the first quarter of 2009. The decrease in NGL production was primarily the result of decreased volumes delivered to our Houston Central plant due in part to shutting down the plant for six days to perform maintenance, complete the connection for ethane and propane lines and prepare for the start-up of our fractionation facilities. For the three months ended March 31, 2010, volumes originating from the Texas segment and delivered to the Houston Central plant decreased 13% from the three months ended March 31, 2009. Natural gas delivered to the Houston Central plant and originating from sources other than the Texas segment decreased 23% from the first quarter of 2009 primarily as a result of a third party pipeline temporarily diverting volumes away from the Houston Central plant for ten days. Please read “— Trends and Uncertainties — Market and Industry Trends and — Commodity Price and Producer Activity.”
 
Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $1.1 million for the three months ended March 31, 2010 compared to $0.8 million for the three months ended March 31, 2009, an increase of $0.3 million, or 38%. This increase is primarily the result of a $0.4 million increase in compressor rental income from Bighorn, which began during the second quarter of 2009, offset by lower margin results from producer services. These lower margin results were primarily due to reduced production levels associated with a weak commodity pricing environment in 2008 and 2009 creating disincentives for producers to drill or to initiate de-watering programs on wells previously drilled.
 
Corporate and Other.  Corporate and other includes our commodity risk management activities and was a loss of $1.4 million for the three months ended March 31, 2010 compared to a gain of $16.1 million for the three months ended March 31, 2009, a decrease of $17.5 million. The loss for the three months ended March 31, 2010 includes $8.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $0.4 million of unrealized losses on our commodity derivative instruments offset by $7.0 million of net cash settlements received on expired commodity derivative instruments. The gain for the three months ended March 31, 2009 includes $25.1 million of net cash settlements received on expired commodity derivative instruments and $0.2 million of unrealized mark-to-market gains on our commodity derivative instruments, offset by $9.2 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.
 
Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $12.1 million for the three months ended March 31, 2010 compared to $12.7 million for the three months ended March 31, 2009. The 5% decrease is attributable to decreases of $0.2 million in our Oklahoma segment and $0.5 million in our Texas segment primarily due to decreased costs for chemicals and field supplies and a reduction in the rental costs of compressors; offset by an increase of $0.1 million in our Rocky Mountains segment related to overhaul expenditures on the compressors we lease to Bighorn.
 
Depreciation and, Amortization.  Depreciation and amortization totaled $15.2 million for the three months ended March 31, 2010 compared with $13.1 million for the three months ended March 31, 2009, an increase of 16%. This increase relates primarily to additional depreciation and amortization recognized due to capital expenditures made subsequent to March 31, 2009 including expenditures relating to the completion of our Saint Jo plant and retirement of certain assets in Oklahoma.


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General and Administrative Expenses.  General and administrative expenses totaled $10.5 million for the three months ended March 31, 2010 compared to $10.7 million for the three months ended March 31, 2009. The 2% decrease consists primarily of a decrease of (i) $0.8 million in expenses associated with acquisition initiatives and (ii) a reduction of $0.2 million in gains on the sale of certain assets, offset by (i) a $0.6 million increase in personnel, compensation and benefits costs and (ii) an increase in legal and accounting fees of $0.2 million.
 
Interest and Other Financing Costs.  Interest and other financing costs totaled $14.9 million for the three months ended March 31, 2010 compared to $14.4 million for the three months ended March 31, 2009, an increase of $0.5 million, or 3%. Interest expense related to our revolving credit facility totaled $2.4 million (including net settlements paid under our interest rate swaps of $1.5 million and net of $0.5 million of capitalized interest) and $1.5 million (including net settlements paid under our interest rate swaps of $1.1 million and net of $1.2 million of capitalized interest) for the three months ended March 31, 2010 and 2009, respectively. Interest and other financing costs for the three months ended March 31, 2010 includes unrealized mark-to-market losses of $0.1 million on undesignated interest rate swaps compared to unrealized mark-to-market gains of $0.1 million for the same period in 2009. Interest expense on our senior unsecured notes decreased to $11.6 million for the three months ended March 31, 2010 from $11.8 million for the three months ended March 31, 2009, primarily related to interest savings as a result of retiring $18.2 million of our 7.75% senior unsecured notes due 2018 during the three months ended March 31, 2009. Amortization of debt issue costs totaled $0.9 million and $1.3 million for the three months ended March 31, 2010 and 2009, respectively. Average borrowings under our credit arrangements for the three months ended March 31, 2010 and 2009 were $823.2 million and $838.1 million with average interest rates of 7.4% for both periods. Please read “— Liquidity and Capital Resources — Description of Our Indebtedness.”
 
Gain on Unsecured Debt Retirement.  During the first quarter of 2009, we repurchased and retired $18.2 million aggregate principal amount of our 7.75% senior unsecured notes due 2018 using available cash and borrowings under our revolving credit facility. As a result of repurchasing the notes below par value, we recognized a gain of $3.9 million in the first quarter of 2009.
 
Cash Flows
 
The following table summarizes our cash flows for each of the periods indicated as reported in the historical consolidated statements of cash flows found in Item 1 of this report.
 
                 
    Three Months Ended March 31,  
    2010     2009  
    (In thousands)  
 
Net cash provided by operating activities
  $ 29,164     $ 35,398  
Net cash used in investing activities
    (18,441 )     (19,451 )
Net cash (used in) provided by financing activities
    (1,267 )     4,662  
 
Our cash flows are affected by a number of factors, some of which we cannot control. These factors include industry and economic conditions, as well as conditions in the financial markets, prices and demand for our services, volatility in commodity prices or interest rates, effectiveness of our hedging program, operational risks and other factors.
 
Operating Cash Flows.  Net cash provided by operating activities was $29.2 million for the three months ended March 31, 2010 compared to $35.4 million for the three months ended March 31, 2009. The decrease in cash provided by operating activities of $6.2 million was attributable to the following changes:
 
  •  risk management activities used an additional $8.6 million of cash flow for the three months ended March 31, 2010 as compared to the three months ended March 31, 2009, primarily because we purchased commodity derivative instruments at a total cost of $7.4 million during the three months ended March 31, 2010, whereas in the three months ended March 31, 2009, we did not purchase commodity derivative instruments;


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partially offset by:
 
  •  a $1.9 million increase in operating activities (consisting of a $2.1 million decrease in operating income and a $4 million increase resulting from the timing of related cash receipts and disbursements) for the three months ended March 31, 2010 compared with the same period in 2009;
 
  •  a $0.4 million increase in cash distributions received from our unconsolidated affiliates (Bighorn, Fort Union, Webb Duval and Southern Dome) in the three months ended March 31, 2010 compared to the three months ended March 31, 2009; and
 
  •  a $0.1 million decrease in interest payments for the months ended March 31, 2010 compared to the same period in 2009 as a result of lower average borrowings.
 
Investing Cash Flows.  Net cash used in investing activities was $18.4 million and $19.5 million for the three months ended March 31, 2010 and 2009, respectively. Investing activities for the three months ended March 31, 2010 included (i) $19.4 million of capital expenditures related to the construction of the gathering lines upstream of our Saint Jo plant, rights-of-way acquisition and construction of the Dewitt-Karnes pipeline header in south Texas, as well as constructing well interconnects to attach volumes in new areas, and (ii) $0.4 million of investment in Bighorn offset by (i) $1.0 million of distributions from Bighorn and Southern Dome in excess of equity earnings and (ii) other investing activities of $0.4 million. Investing activities for the first quarter of 2009 included (i) $19.8 million of capital expenditures related to the construction of our Saint Jo plant and related projects, progress payments for the purchase of compression and constructing well interconnects to attach volumes in new areas, (ii) $0.6 million of investment in Bighorn and (iii) other investing activities of $0.6 million, offset by $1.6 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings.
 
Financing Cash Flows.  Net cash used in financing activities totaled $1.3 million during the three months ended March 31, 2010 and included (i) net repayments under our revolving credit facility of $135.0 million and (ii) distributions to our unitholders of $31.5 million, offset by (i) net proceeds from our public offering of common units in March 2010 (including units issued upon the underwriters’ exercise of their option to purchase additional units) of $164.5 million and (ii) proceeds from the exercise of unit options of $0.7 million. Net cash provided by financing activities totaled $4.7 million during the three months ended March 31, 2009 and included borrowings under our revolving credit facility of $50.0 million, offset by (i) $14.3 million to retire a portion of our 7.75% senior unsecured notes due 2018 and (ii) distributions to our unitholders of $31.0 million.
 
Liquidity and Capital Resources
 
Sources of Liquidity.  Cash generated from operations, borrowings under our revolving credit facility and funds from equity and debt offerings are our primary sources of liquidity. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on our revolving credit facility and senior unsecured notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our revolving credit facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions.
 
For additional discussion, please read “— Our Long-Term Growth Strategy” under Item 7 of our 2009 10-K.
 
Effects of Recent Economic Changes; Outlook.  Commodity prices during 2009 led to a decline in drilling activity, and in turn a decline in the volumes of natural gas we gathered and processed in 2009 and the beginning of 2010. Although commodity prices and financial market conditions have continued to recover, improvements in drilling activity remain sporadic, and it remains unclear when producers will undertake sustained increases in lean gas drilling activity throughout the areas in which we operate. Our ability to generate cash from operations, and to comply with the covenants under our debt instruments, will be adversely affected if we experience declining volumes in combination with unfavorable commodity prices over a sustained period.


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We have been able to offset the effects of lower prices using commodity derivative instruments we acquired during the favorable pricing environment that prevailed before late 2008; however, we cannot use derivative instruments to offset the effects of lower volumes. In addition, the strike prices of derivative instruments we acquired in 2008 are substantially higher than those of instruments we acquired in the fourth quarter of 2009 and first and second quarters of 2010, as well as the strike prices available for commodity derivative instruments we could purchase today. Derivative instruments reflect commodity price forward curves in effect at the time of purchase, and our more recently purchased derivative instruments will not be as beneficial as those we acquired in 2008.
 
We believe that cash from operations and our revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the next 12 months. If our plans or assumptions change, are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions and organic expansion have been, and our management believes will continue to be, key elements of our business strategy. In addition, we continue to consider opportunities for strategic greenfield projects. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt or equity issuances, or both. Our ability to obtain capital to implement our growth strategy over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets, and other financial and business factors, many of which are beyond our control.
 
Generally, we believe that financial markets now offer greater liquidity than was available at the height of the financial crisis, but at a higher cost than we would have experienced before the financial crisis.
 
Capital Expenditures.  The natural gas gathering, transmission and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:
 
  •  maintenance capital expenditures, which are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and
 
  •  expansion capital expenditures, which are capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance.
 
During the three months ended March 31, 2010, our capital expenditures totaled $21.8 million, consisting of $1.4 million of maintenance capital and $20.4 million of expansion capital. We funded our capital expenditures with funds from operations and borrowings under our revolving credit facility. Expansion capital expenditures were related to the construction and gathering lines upstream of our Saint Jo plant, rights-of-way acquisition, construction of the Dewitt-Karnes pipeline header in south Texas, completion of the Burbank plant in Oklahoma, as well as constructing well interconnects to attach volumes in new areas. Based on our current scope of operations, we anticipate incurring approximately $10 million to $12 million of maintenance capital expenditures over the next 12 months. We anticipate incurring approximately $125 to $140 million in expansion capital expenditures in 2010 primarily related to enhancing the capabilities and capacities of our current asset base.
 
Cash Distributions.  The amount needed to pay the current distribution of $0.575 per unit, or $2.30 per unit annualized, to our common unitholders is as follows (in thousands):
 
                 
    One Quarter     Four Quarters  
 
Common units(1)
  $ 38,134     $ 152,536  
                 


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(1) Includes distributions on restricted common units and phantom units issued under our Long-Term Incentive Plan (“LTIP”). Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of April 30, 2010, we had 105,101 outstanding restricted units and 738,056 outstanding phantom units.
 
Our Indebtedness
 
As of March 31, 2010 and December 31, 2009, our aggregate outstanding indebtedness totaled $717.2 million and $852.2 million, respectively, and we were in compliance with our financial debt covenants under our revolving credit facility and our incurrence covenant under the indentures of our senior notes.
 
Credit Ratings.  Moody’s Investors Service has assigned a Corporate Family rating of Ba3 with a negative outlook, a B1 rating for our senior unsecured notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a stable outlook and a B+ rating for our senior unsecured notes.
 
Revolving Credit Facility.  As of March 31, 2010, we had $135.0 million of outstanding borrowings under our $550 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent.
 
Our revolving credit facility matures on October 18, 2012. Our revolving credit facility includes 29 lenders with commitments ranging from $1 million to $60 million, with the largest commitment representing 10.9% of the total commitments. Future borrowings under the facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restriction so long as we are in compliance with its terms, including the financial covenants described below. Our revolving credit facility provides for up to $50 million in standby letters of credit. As of March 31, 2010 and December 31, 2009, we had no letters of credit outstanding. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position.
 
At March 31, 2010, our ratio of total debt to EBITDA was 3.7x, and our ratio of EBITDA to interest expense was 3.5x. Based on our ratio of total debt to EBITDA at March 31, 2010, we have approximately $247.0 million of available borrowing capacity under the revolving credit facility before we reach the maximum total debt to EBITDA ratio of 5.0 to 1.0.
 
If an event of default exists under the revolving credit facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the revolving credit facility.
 
Senior Unsecured Notes.  The indentures governing our senior unsecured notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the senior unsecured notes indentures) is at least 1.75x. At March 31, 2010, our ratio of EBITDA to fixed charges was 3.3x.
 
For additional details on the revolving credit facility and Senior Notes, please read Note 5 “Long-Term Debt,” to our unaudited consolidated financial statements included in Item 1 of this report.
 
Off-Balance Sheet Arrangements
 
We had no off-balance sheet arrangements as of March 31, 2010.
 
Recent Accounting Pronouncements
 
For information on new accounting pronouncements, please read Note 2 “New Accounting Pronouncements,” to our unaudited consolidated financial statements included in Item 1 of this report.
 
Critical Accounting Policies
 
A discussion of our critical accounting policies for revenue recognition, impairment of long-lived assets, risk management activity and equity method of accounting for unconsolidated affiliates, which remain unchanged, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2009.


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Item 3.   Quantitative and Qualitative Disclosures about Market Risk.
 
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.
 
Commodity Price Risk
 
NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing or conditioning at our processing plants or third-party processing plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) the cost of third-party transportation and fractionation services. The following discussion describes our commodity price risks as of March 31, 2010. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly.
 
Oklahoma.  A majority of the processing contracts in our Oklahoma segment are percentage-of-proceeds arrangements. Under these arrangements, we purchase and process natural gas from producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase and revenues and gross margins decrease as natural gas and NGL prices decrease. Our Oklahoma segment also has fixed-fee contracts and percentage-of-index contracts.
 
Texas.  Our Texas pipeline systems purchase natural gas for transportation and resale and also transport and provide other services on a fee-for-service basis. A significant portion of the margins we realize from purchasing and reselling the natural gas is based on a percentage of a stated index price. Accordingly, these margins decrease in periods of low natural gas prices and increase during periods of high natural gas prices. The fees we charge to transport natural gas for the accounts of others are primarily fixed, but our Texas contracts also include a percentage-of-index component in a number of cases.
 
While we have increasingly focused on obtaining fee-based arrangements, a significant portion of the gas processed by our Texas segment is still processed under keep-whole with fee arrangements. Under these arrangements, increases in NGL prices or decreases in natural gas prices generally have a positive impact on our processing gross margins and, conversely, a reduction in NGL prices or increases in natural gas prices generally negatively impact our processing gross margins. However, the ability of our Houston Central plant to operate in a conditioning mode provides an operational hedge that allows us to reduce our Texas processing operations’ commodity price exposure. In conditioning mode, increases in natural gas prices have a positive impact on our margins.
 
Rocky Mountains.  Substantially all of our Rocky Mountains contractual arrangements as well as the contractual arrangements of Fort Union and Bighorn are fixed-fee arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. The cash flow from these arrangements is directly related to natural gas volumes and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, our cash flow would also decline.
 
Other Commodity Price Risks.  Although we seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations, we experience imbalances between our natural gas purchases and sales from time to time. For example, a producer could fail to deliver or deliver in excess of contracted volumes, or a customer could take more or less than contracted volumes. To the extent our purchases and sales of natural gas are not balanced, we face increased exposure to commodity prices with respect to the imbalance.


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We purchase and sell natural gas under a variety of pricing arrangements, for example, by reference to first of the month index prices, daily index prices or a weighted average of index prices over a given period. Our goal is to minimize commodity price risk by aligning the combination of pricing methods and indices under which we purchase natural gas in each of our segments with the combination under which we sell natural gas in these segments, although it is not always possible to do so.
 
Basis risk is the risk that the value of a hedge may not move in tandem with the value of the actual price exposure that is being hedged. Any disparity in terms, such as product, time or location, between the hedge and the underlying exposure creates the potential for basis risk. Our long position in natural gas in Oklahoma can serve as a hedge against our short position in natural gas in Texas. To the extent we rely on natural gas from our Oklahoma segment, which is priced primarily on the CenterPoint East index, to offset a short position in natural gas in our Texas segment, which is priced on the Houston Ship Channel index, we are subject to basis risk. In addition, we are subject to basis risk to the extent we hedge Oklahoma NGL volumes because, due to the extremely limited forward market for Conway-based hedge instruments, we use Mt. Belvieu-priced hedge instruments for our Oklahoma NGL volumes. The CenterPoint East and Houston Ship Channel indices and the Mt. Belvieu and Conway indices historically have been highly correlated; however, these indices displayed greater variability beginning in late 2008 and for much of 2009. These basis differences returned to a correlation more consistent with their historical pattern in late 2009, but through May 3, 2010, the difference between Mt. Belvieu and Conway had widened to $5.70 per barrel. To mitigate basis risk affecting our natural gas positions in Oklahoma and Texas, we entered into basis swaps on the CenterPoint East index and the Houston Ship Channel indices for 2010.
 
Sensitivity.  In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $0.2 million to our total segment gross margin for the three months ended March 31, 2010. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in an immaterial change to our total segment gross margin, and vice versa, for the three months ended March 31, 2010. These relationships are not necessarily linear. As actual prices have fallen below the strike prices of our hedges in the first quarter of 2010, sensitivity to further changes in commodity prices have been reduced. Also, if processing margins are negative, we can operate our Houston Central plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact on our total segment gross margin.
 
Our Hedge Portfolio
 
Commodity Hedges.  As of March 31, 2010, our commodity hedge portfolio totaled a net asset of $42.9 million, which consists of assets aggregating $47.5 million and liabilities aggregating $4.6 million. For additional information, please read “— Recent Developments” in Item 2 of this report and Note 11, “Risk Management Activities,” to our unaudited consolidated financial statements included in Item 1 of this report for tables summarizing our commodity hedge portfolio as of March 31, 2010.
 
Interest Rate Swaps.  As of March 31, 2010, the fair value of our interest rate swaps liability totaled $8.1 million. For additional information on our interest rate swaps, please read Note 11, “Risk Management Activities,” to our unaudited consolidated financial statements included in Item 1 of the report.
 
Counterparty Risk
 
We are diligent in attempting to ensure that we provide credit only to credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the three months ended March 31, 2010, DCP Midstream (21%), ONEOK Energy Services, L.P. (19%), ONEOK Hydrocarbons, L.P. (19%), Kinder Morgan (8%) and Enterprise Products Operating, L.P. (7%), collectively, accounted for approximately 74% of our revenue. As of March 31, 2010, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services. Companies accounting for another approximately 20% of our revenue have an investment grade parent,


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are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.
 
We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of March 31, 2010, Barclays Bank PLC (47%), Deutsche Bank AG (29%) and JP Morgan (11%) accounted for approximately 87% of the value of our net commodity hedging positions. As of March 31, 2010, all of these counterparties were rated A2 and A or better by Moody’s Investors Service and Standard & Poor’s Ratings Services. Our hedge counterparties have not posted collateral to secure their obligations to us.
 
We have historically experienced minimal collection issues with our counterparties; however, nonpayment or nonperformance by one or more significant counterparties could adversely impact our liquidity.
 
Item 4.   Controls and Procedures.
 
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at March 31, 2010 at the reasonable assurance level. There has been no change in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2010 that has materially affected or is reasonably likely to materially affect such internal controls over financial reporting.


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PART II-OTHER INFORMATION
 
Item 1.   Legal Proceedings.
 
Please read Note 9, “Commitments and Contingencies,” to our unaudited consolidated financial statements included in Part I, Item 1 of this report which is incorporated in this item by reference.
 
Item 1A.   Risk Factors.
 
In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described in this item and under Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2009. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.
 
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect our services.
 
The federal Congress is considering legislation that would amend the federal Safe Drinking Water Act by repealing an exemption for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens for producers such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of any federal or state legislation or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult and costly for producers to complete natural gas wells in shale formations and adversely affect the gathering, processing and fractionation services that we render for those producers. Moreover, the U.S. Environmental Protection Agency, or “EPA,” announced only recently, on March 18, 2010, that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. Consequently, even if the current federal legislation is not adopted, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing activities.


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Item 6.   Exhibits.
 
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
 
         
Number
 
Description
 
  2 .1   Purchase Agreement dated as of August 31, 2007 among Copano Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and Cantera Resources Holdings LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed October 25, 2007).
  2 .2   Contribution Agreement dated as of April 5, 2007 by and among Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, L.L.C. and Copano Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed April 11, 2007).
  3 .1   Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
  3 .2   Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
  3 .3   Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed April 30, 2007).
  3 .4   Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed May 4, 2007).
  3 .5   Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. dated October 19, 2007 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed October 25, 2007).
  3 .6   Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C., dated October 19, 2007 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed October 25, 2007).
  4 .1   Indenture dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
  4 .2   Rule 144A Global Note representing $224,500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed February 8, 2006).
  4 .3   Regulation S Global Note representing $500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed February 8, 2006).
  4 .4   Indenture, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 19, 2008).
  4 .5   Form of Global Note representing 7.75% Senior Notes due 2018 (included in 144A/Regulation S Appendix to Exhibit 4.7 above).
  10 .1   Administrative and Operating Services Agreement effective January 1, 2010, among Copano/Operations, Inc. and CPNO Services, L.P. (incorporated by reference to Exhibit 10.3 to Annual Report on Form 10-K filed March 1, 2010).
  10 .2   2010 Administrative Guidelines for the Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed February 23, 2010).
  31 .1*   Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
  31 .2*   Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
  32 .1*   Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
  32 .2*   Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
 
 
* Filed herewith.
 
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on May 7, 2010.
 
Copano Energy, L.L.C.
 
  By: 
/s/  R. Bruce Northcutt
R. Bruce Northcutt
President and Chief Executive Officer
(Principal Executive Officer)
 
  By: 
/s/  Carl A. Luna
Carl A. Luna
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)


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