EX-99.1 2 ex99-1.htm COPANO ENERGY, L.L.C. EARNINGS RELEASE ex99-1.htm
 
Exhibit 99.1
 
News Release
 
         Contacts:  
Carl A. Luna, SVP and CFO
Copano Energy, L.L.C.
713-621-9547
 
Jack Lascar / jlascar@drg-l.com
Anne Pearson/ apearson@drg-l.com
DRG&L/ 713-529-6600
     
   
FOR IMMEDIATE RELEASE
  


Copano Energy Reports Third Quarter 2012 Results

HOUSTON, November 7, 2012 — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three months ended September 30, 2012.

Third Quarter 2012 Highlights:
 
·
Fee-based Texas segment rich natural gas volumes drive third quarter performance
 
·
Total distributable cash flow of $57.1 million, a 55% increase from third quarter 2011
 
·
Total segment gross margin of $75.1 million, a 16% increase from the prior year period
 
·
Adjusted EBITDA of $73.0 million, a 41% increase from the prior year period
 
·
Volumes gathered from the Eagle Ford Shale play averaged 567,000 MMBtu/d, a 248% increase from the prior year period
 
·
Texas segment NGL production of over 54,000 Bbls/d, a 75% increase from third quarter 2011
“Our third quarter results highlight our strengthening operational performance and continued progress in executing on our Eagle Ford strategy,” said R. Bruce Northcutt, Copano’s President and Chief Executive Officer. “Despite lower NGL prices compared to the second quarter of this year, fee-based volumes from the Eagle Ford have continued to grow, delivering strong gross margins for our Texas business segment.
“Our organic growth projects in the play remain on track and we look forward to the positive impact they will have on total distributable cash flow as our Eagle Ford strategy continues to develop,” Northcutt added.

Third Quarter Financial Results
Total distributable cash flow was $57.1 million, a 55% increase from the third quarter of 2011, and a 45% increase from the second quarter of 2012.  The increase from the prior-year period was primarily due to:
 
·
increased throughput from the Eagle Ford Shale, north Barnett Shale Combo and Woodford Shale plays, and
 
·
a $9.7 million gain related to the sale of the Lake Charles plant in Louisiana.
These benefits were partially offset by lower natural gas liquids (NGL) prices and higher interest and operating expenses.
Third-quarter 2012 total distributable cash flow represents 124% coverage of the third-quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date, which included an additional 6,526,078 common units issued in our equity offering that closed in late October 2012.  Excluding the gain on the sale of the Lake Charles plant, third-quarter 2012 total distributable cash flow coverage was approximately 103%.  Excluding the newly issued units and the gain on sale of the Lake Charles plant, third-quarter 2012 total distributable cash flow coverage was approximately 112%.
Revenue for the third quarter of 2012 increased 4% from the third quarter of 2011 to $366.4 million, and 15% from the second quarter of 2012.  Total segment gross margin increased 16% from the third quarter of 2011 to $75.1 million, and 3% from the second quarter of 2012.  Adjusted EBITDA increased 41% from the third quarter of 2011 to $73.0 million, and 25% from the second quarter of 2012.  Net income to common units was $19.8 million for the third quarter of 2012 compared to net loss of $166.0 million for the third quarter of 2011.
 
 
1
 
 
Corporate and other activities, which include Copano’s commodity risk management efforts, resulted in a loss of $3.7 million for the third quarter of 2012, consisting of $5.9 million in non-cash amortization expense and $2.6 million of unrealized losses on commodity derivative instruments, offset by $4.8 million of net cash settlements received.  Corporate and other activities resulted in a $8.0 million loss for the third quarter of 2011 consisting of $7.4 million of non-cash amortization expense and $2.9 million of net cash settlements paid, offset by $2.3 million of unrealized gain on commodity derivative instruments.  Corporate and other activities resulted in a $3.4 million gain for the second quarter of 2012 consisting of $3.4 million of net cash settlements received and $5.0 million of unrealized gains on commodity derivative instruments, offset by $5.0 million of non-cash amortization expense.
Total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this news release.  Please read “Use of Non-GAAP Financial Measures” beginning on page 5 of this news release.
 
Third Quarter Operating Results by Segment
Texas
Segment gross margin for Texas increased 24% from the third quarter of 2011 to $55.2 million, and increased 12% from the second quarter of 2012.  The increase from the prior year was primarily a result of volume growth from the Eagle Ford Shale and north Barnett Shale Combo plays, partially offset by a decline in leaner gas volumes at the Houston Central complex, which were displaced to accommodate richer Eagle Ford Gathering fee-based gas volumes.
During the third quarter of 2012, Texas segment service throughput volumes averaged  897,601 MMBtu/d of natural gas, an increase of 17% from the third quarter of 2011.  The Texas segment gathered an average of 557,457 MMBtu/d of natural gas, an increase of 20% over the third quarter of 2011, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays.  Volumes processed at Copano’s plants and third-party plants in Texas averaged 824,196 MMBtu/d during the third quarter of 2012, an increase of 20% over the third quarter of 2011 primarily due to increased volumes from the north Barnett Shale Combo play and at the Lake Charles plant.  Third-quarter NGL production averaged 54,142 Bbls/d at Copano-owned plants and third-party plants, an increase of 75% from the third quarter of 2011, reflecting a substantial increase in the NGL content of volumes at the Houston Central complex, and increased volumes at the Saint Jo plant in the north Barnett Shale Combo play.
Eagle Ford Gathering, Copano’s unconsolidated joint venture with Kinder Morgan, has been in full service since December 2011 and provided gathering services for an average of 319,919 MMBtu/d during the third quarter of 2012.  Texas segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Eagle Ford Gathering, which is accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.” For the third quarter of 2012, equity earnings and distributions from Eagle Ford Gathering totaled $9.2 million and $6.3 million, respectively.
Oklahoma
Segment gross margin for Oklahoma was $22.9 million for the third quarter of 2012, a decrease of 18% compared to the third quarter of last year and an increase of 14% from the second quarter of 2012.  The year-over-year decrease was due primarily to lower NGL and natural gas prices, which resulted in a 24% decrease in realized margins on service throughput compared to the third quarter of 2011 ($0.80 per MMBtu in 2012 compared to $1.05 per MMBtu in 2011).  This decrease was partially offset by an increase in service throughput attributable to lean gas volume growth from the Woodford Shale play.
The Oklahoma segment gathered an average of 313,414 MMBtu/d of natural gas, an increase of 9% compared to the third quarter of 2011, due primarily to lean gas from the Woodford Shale area, which increased 20% compared to the third quarter of 2011.  Volumes processed at wholly owned and third-party plants in Oklahoma were flat compared to the third quarter of 2011, averaging 157,775 MMBtu/d.  Third-quarter NGL production at Copano-owned plants and third-party plants averaged 16,207 Bbls/d, a decrease of 7% from the third quarter of 2011.
Rocky Mountains
Segment gross margin for the Rocky Mountains segment totaled $0.6 million in the third quarter of 2012 compared to $0.4 million for the third quarter of 2011 and $0.2 million for the second quarter of 2012.  Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Bighorn Gas Gathering and Fort Union Gas Gathering, which are accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.”
 
 
2
 
 
Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 4% to 694,961 MMBtu/d in the third quarter of 2012 as compared to 670,543 MMBtu/d in the third quarter of 2011.  The volume increase is due primarily to producers increasing volumes on Fort Union to access downstream markets; however, because Fort Union has firm volume commitments from these producers, the increase did not have a material impact on Copano’s equity earnings or distributions.  For the third quarter of 2012, combined equity earnings for Bighorn and Fort Union totaled $3.0 million compared to equity losses of $164.1 million for the same period in 2011, which included a $165.0 million impairment in 2011. Combined distributions from Bighorn and Fort Union totaled $5.1 million in the third quarter of 2012 compared to $5.0 million in the third quarter of last year.
 
Cash Distributions
On October 10, 2012, Copano announced its third quarter 2012 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, which will be paid on November 8, 2012 to common unitholders of record at the close of business on October 31, 2012.  This distribution is unchanged from the second quarter of 2012.
 
Conference Call Information
Copano will hold a conference call on November 8, 2012 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) to discuss its third quarter 2012 financial results.  To participate in the call, dial (480) 629-9643 and ask for the Copano call at least 10 minutes prior to the start time, or access it live over the internet at http://www.copano.com on the “Investor Overview” page of the “Investor Relations” section of Copano’s website.
A replay of the audio webcast will be available shortly after the call on Copano’s website.  A telephonic replay will be available through November 15, 2012 by calling (303) 590-3030 and using the pass code 4570334#.
 
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin.  The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.  Copano’s non-GAAP financial measures may not be comparable to similarly titled measures of other companies, who may not calculate their measures in the same manner.
Copano’s management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets.  Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the various financial measures that its management uses in evaluating its performance because it allows them to independently evaluate Copano’s performance with the same information used by management.
Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma and Wyoming.  For more information, please visit http://www.copano.com.

 
This press release includes “forward-looking statements,” as defined by the Securities and Exchange Commission.  Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements.  These statements include, but are not limited to, statements about future producer activity and Copano’s total distributable cash flow and distribution coverage.  These statements are based on management’s experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable.  Important factors that could cause actual results to differ materially from those in forward-looking statements include the following risks and uncertainties, many of which are beyond Copano’s control: the volatility of prices and market demand for natural gas and natural gas liquids; Copano’s ability to continue to connect new sources of natural gas, crude oil and condensate, and the NGL content of new gas supplies; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production; producers’ ability to drill and successfully complete and connect new natural gas supplies; Copano’s ability to attract and retain key customers; performance by producers, customers and service providers under their contracts with Copano; the availability of downstream transportation and other facilities for natural gas and NGLs; operational risks affecting the performance of Copano or third-party processing, fractionation plants and other facilities; Copano’s ability to access or construct new processing, fractionation and transportation capacity; higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of operational, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano’s quarterly and annual reports filed with the Securities and Exchange Commission.  Copano does not undertake to update any forward-looking statement except as provided by law.


–financial statements follow –

 
3
 
 

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
 
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
             
   
2012
    
2011
    
2012
    
2011
  
   
(In thousands, except per unit information)
  
Revenue:
                        
Natural gas sales
  $ 97,614     $ 120,815     $ 253,819     $ 348,538  
Natural gas liquids sales
    205,464       191,370       589,431       521,129  
Transportation, compression and processing fees
    49,314       30,337       132,394       82,706  
Condensate and other
    14,001       11,169       45,280       37,299  
Total revenue
    366,393       353,691       1,020,924       989,672  
                                 
Costs and expenses:
                                
Cost of natural gas and natural gas liquids(1) 
     284,936       281,858       789,369       779,986  
Transportation (1) 
     6,365       6,991       18,785       19,202  
Operations and maintenance
    19,242       16,091       56,171       46,953  
Depreciation and amortization
     19,259       16,911       57,409       51,143  
Impairment
     -       5,000       28,744       5,000  
General and administrative
    13,697       10,031       38,939       34,530  
Taxes other than income
    1,983       1,502       5,459       4,029  
Equity in (earnings) loss from unconsolidated affiliates
    (12,558)       161,589       89,733       158,581  
Gain on sale of operating assets
     (9,716)       -       (9,716)        -  
Total costs and expenses
    323,208       499,973       1,074,893       1,099,424  
                                 
Operating income (loss)
     43,185       (146,282)       (53,969)       (109,752)  
Other income (expense):
                                
Interest and other income
    11       16       570       31  
Loss on refinancing of unsecured debt
    -       -       -       (18,233)  
Interest and other financing costs
    (13,797)       (11,080)       (42,823)       (34,450)  
Income (loss) before income taxes
     29,399       (157,346)       (96,222)       (162,404)  
Provision for income taxes
    (474)       (390)       (1,406)       (1,161)  
Net income (loss)
     28,925       (157,736)       (97,628)       (163,565)  
Preferred unit distributions
     (9,138)       (8,279)       (26,751)       (24,235)  
Net income (loss) to common units
   $ 19,787     $ (166,015)     $ (124,379)     $ (187,800)  
                                 
Basic net income (loss) per common unit:
                                
Net income (loss) per common unit
   $ 0.27     $ (2.51)     $ (1.73)     $ (2.84)  
Weighted average number of common units
    72,395       66,246       71,887       66,125  
                                 
Diluted net income (loss) per common unit:
                                
Net income (loss) per common unit
   $ 0.23     $ (2.51)     $ (1.73)     $ (2.84)  
Weighted average number of common units
    85,682       66,246       71,887       66,125  
                                 
                                 
Distributions declared per common unit
   $ 0.575     $ 0.575     $ 1.725     $ 1.725  
________
                                
 _______________                  
(1) Exclusive of operations and maintenance, depreciation and amortization and impairment shown separately below.
  
 
 
4
 
 

COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
   
Nine Months Ended September 30,
 
 
 
   
2012
  
2011 
 
 
 
 
 
 
 
Cash Flows From Operating Activities:
    
(In thousands)
Net loss
  
$
 (97,628)
  
$
 (163,565)
Adjustments to reconcile net loss to net cash provided by operating activities:
            
Depreciation and amortization
    
 57,409 
    
 51,143 
Impairment
    
 28,744 
    
 5,000 
Amortization of debt issue costs
    
 2,987 
    
 2,855 
Equity in loss from unconsolidated affiliates
    
 89,733 
    
 158,581 
Distributions from unconsolidated affiliates
    
 31,229 
    
 17,961 
Gain on sale of operating assets
    
 (9,716)
    
 - 
Loss on refinancing of unsecured debt
    
 - 
    
 18,233 
Non-cash gain on risk management activities, net
    
 (4,327)
    
 (4,723)
Equity-based compensation
    
 5,246 
    
 7,445 
Deferred tax provision
    
 240 
    
 253 
Other non-cash items
    
 5,197 
    
 (86)
Changes in assets and liabilities, net of acquisitions:
    
 - 
    
 - 
Accounts receivable
    
 8,032 
    
 (11,132)
Prepayments and other current assets
    
 1,861 
    
 (2,952)
Risk management activities
    
 8,135 
    
 11,353 
Accounts payable
    
 (24,371)
    
 17,459 
Other current liabilities
    
 21,010 
    
 14,964 
Net cash provided by operating activities
    
 123,780 
    
 122,789 
 
 
 
 
 
 
 
Cash Flows From Investing Activities:
            
Additions to property, plant and equipment
    
 (247,179)
    
 (175,323)
Additions to intangible assets
    
 (6,869)
    
 (5,316)
Acquisitions
    
 - 
    
 (16,084)
Investments in unconsolidated affiliates
    
 (60,677)
    
 (105,111)
Distributions from unconsolidated affiliates
    
 3,279 
    
 2,368 
Escrow cash
    
 - 
    
 6 
Proceeds from sale of assets
    
 23,850 
    
 248 
Other
    
 2,604 
    
 98 
Net cash used in investing activities
    
 (284,992)
    
 (299,114)
 
 
 
 
 
 
 
Cash Flows From Financing Activities:
            
Proceeds from long-term debt
    
 420,375 
    
 725,000 
Repayment of long-term debt
    
 (322,000)
    
 (412,665)
Payments of premiums and expenses on redemption of unsecured debt
    
 - 
    
 (14,572)
Deferred financing costs
    
 (3,539)
    
 (15,743)
Distributions to unitholders
    
 (126,090)
    
 (114,834)
Proceeds from public offering of common units, net of underwriting discounts
            
and commissions of $7,590
    
 188,083 
    
 - 
Equity offering costs
    
 (379)
    
 (4)
Proceeds from option exercises
    
 1,284 
    
 2,747 
Net cash provided by financing activities
    
 157,734 
    
 169,929 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
    
 (3,478)
    
 (6,396)
Cash and cash equivalents, beginning of year
    
 56,962 
    
 59,930 
Cash and cash equivalents, end of period
  
$
 53,484 
  
$
 53,534 
 
 
5
 
 
 
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
UNAUDITED CONSOLIDATED BALANCE SHEETS
 
 
 
September 30,
    
December 31,
  
 
2012
    
2011
  
   
 
    
 
  
   
(In thousands, except unit
 information)
  
ASSETS
  
Current assets:
  
 
    
 
  
Cash and cash equivalents
  $ 53,484     $ 56,962  
Accounts receivable, net
     112,165       119,193  
Risk management assets
    16,420       4,322  
Prepayments and other current assets
    3,254       5,114  
Total current assets
    185,323       185,591  
                 
Property, plant and equipment, net
    1,301,813       1,103,699  
Intangible assets, net
    161,652       192,425  
Investments in unconsolidated affiliates
    480,118       544,687  
Escrow cash
    1,848       1,848  
Risk management assets
    6,941       6,452  
Other assets, net
    28,163       29,895  
Total assets
  $ 2,165,858     $ 2,064,597  
                 
LIABILITIES AND MEMBERS' CAPITAL
  
Current liabilities:
                
Accounts payable
   $ 137,232     $ 155,921  
Accrued capital expenditures
     9,841       7,033  
Accrued interest
    25,022       8,686  
Accrued tax liability
    1,148       1,182  
Risk management liabilities
    1,512       3,565  
Other current liabilities
    22,974       15,007  
Total current liabilities
    197,729       191,394  
                 
Long term debt (includes $3,194 and $0 bond premium as of September 30, 2012
                
and December 31, 2011, respectively)
    1,092,719       994,525  
Deferred tax liability
    2,440       2,199  
Other noncurrent liabilities
    9,893       4,581  
                 
Commitments and contingencies
                
Members’ capital:
                
Series A convertible preferred units, no par value, 12,582,468 units and
               
11,684,074 units issued and outstanding as of September 30, 2012 and
                
December 31, 2011, respectively  
     285,168       285,168  
Common units, no par value, 72,411,407 units and 66,341,458 units issued and
               
outstanding as of September 30, 2012 and December 31, 2011, respectively  
     1,353,900       1,164,853  
Paid in capital
    69,966       62,277  
Accumulated deficit
    (848,066 )     (624,121 )
Accumulated other comprehensive income (loss)
     2,109       (16,279 )
      863,077       871,898  
Total liabilities and members’ capital
  $ 2,165,858     $ 2,064,597  
                 
 
 
6
 
 
 
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
 
UNAUDITED RESULTS OF OPERATIONS
                         
   
Three Months Ended
September 30,
    
Nine Months Ended
 September 30,
  
   
2012
    
2011
    
2012
    
2011
  
   
($ In thousands)
  
Total segment gross margin(1) 
   $ 75,092     $ 64,842     $ 212,770     $ 190,484  
Operations and maintenance expenses
     19,242       16,091       56,171       46,953  
Depreciation and amortization
     19,259       16,911       57,409       51,143  
Impairment
     -       5,000       28,744       5,000  
General and administrative expenses
    13,697       10,031       38,939       34,530  
Taxes other than income
    1,983       1,502       5,459       4,029  
Equity in (earnings) loss from unconsolidated affiliates(2)(3) 
     (12,558 )     161,589       89,733       158,581  
Gain on sale of operating assets
     (9,716 )     -       (9,716 )     -  
Operating income (loss)
     43,185       (146,282 )     (53,969 )     (109,752 )
Loss on refinancing of unsecured debt
    -       -       -       (18,233 )
Interest and other financing costs, net
    (13,786 )     (11,064 )     (42,253 )     (34,419 )
Provision for income taxes
    (474 )     (390 )     (1,406 )     (1,161 )
Net income (loss)
     28,925       (157,736 )     (97,628 )     (163,565 )
Preferred unit distributions
     (9,138 )     (8,279 )     (26,751 )     (24,235 )
Net income (loss) to common units
   $ 19,787     $ (166,015 )   $ (124,379 )   $ (187,800 )
                                 
Basic net income (loss) per common unit
   $ 0.27     $ (2.51 )   $ (1.73 )   $ (2.84 )
Weighted average number of common units - basic
     72,395       66,246       71,887       66,125  
Diluted net income (loss) per common unit
   $ 0.23     $ (2.51 )   $ (1.73 )   $ (2.84 )
Weighted average number of common units - diluted
     85,682       66,246       71,887       66,125  
                                 
Total segment gross margin:
                                
Texas
  $ 55,236     $ 44,540     $ 149,678     $ 135,685  
Oklahoma
     22,948       27,876       67,318       79,623  
Rocky Mountains(4) 
     624       432       1,169       2,245  
Segment gross margin
     78,808       72,848       218,165       217,553  
Corporate and other(5) 
     (3,716 )     (8,006 )     (5,395 )     (27,069 )
Total segment gross margin(1) 
   $ 75,092     $ 64,842     $ 212,770     $ 190,484  
                                 
Segment gross margin per unit:
                                
Texas:
                                
Service throughput ($/MMBtu)
   $ 0.67     $ 0.63     $ 0.59     $ 0.71  
Oklahoma:
                                
Service throughput ($/MMBtu)
   $ 0.80     $ 1.05     $ 0.77     $ 1.04  
                                 
Volumes:
                                
Texas: (6)
                                
Service throughput (MMBtu/d)(7) 
     897,601       765,744       922,256       694,802  
Pipeline throughput (MMBtu/d)
    557,457       463,321       563,404       436,210  
Plant inlet volumes (MMBtu/d)
    824,196       686,398       830,755       612,405  
NGLs produced (Bbls/d)
    54,142       30,904       46,239       27,040  
Oklahoma:(8)
                                
Service throughput (MMBtu/d)(7) 
     313,414       288,440       318,851       280,689  
Plant inlet volumes (MMBtu/d)
    157,775       158,070       157,645       154,439  
NGLs produced (Bbls/d)
    16,207       17,453       16,729       16,945  
                                 
 
 
 
7
 
Capital Expenditures:
                        
Maintenance capital expenditures
  $ 1,743     $ 3,510     $ 7,984     $ 11,111  
Expansion capital expenditures
    95,869       82,675       259,794       203,576  
Total capital expenditures
  $ 97,612     $ 86,185     $ 267,778     $ 214,687  
                                 
Operations and maintenance expenses:
                                
Texas
  $ 11,548     $ 9,082     $ 33,441     $ 26,815  
Oklahoma
     7,649       6,930       22,592       19,943  
Rocky Mountains
    45       79       138       195  
Total operations and maintenance expenses
   $ 19,242     $ 16,091     $ 56,171     $ 46,953  
    _____________________
 
(1)
Total segment gross margin is a non-GAAP financial measure.  Please read Unaudited Non-GAAP Financial Measures” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
 
 
(2)
During the three months ended March 31, 2012, Copano recorded a $120 million non-cash impairment charge relating to its investments in Bighorn and Fort Union.
 
 
(3)
The following table summarizes the results and volumes associated with Copano’s unconsolidated affiliates ($ in thousands):
 
     
Three Months Ended September 30,
  
     
2012
    
2011
  
     
Volume
    
Equity (Earnings)/Loss
    
Volume
    
Equity (Earnings)/Loss
  
Eagle Ford Gathering
           $ (9,174 )         $ (2,016 )
     Pipeline throughput(a) 
(MMBtu/d)
     319,919               38,652          
     NGLs produced(b) 
(Bbls/d)
     12,526               —          
Liberty Pipeline Group(c) 
(Bbls/d)
     25,083       37       2,635       59  
Webb Duval(d) 
(MMBtu/d)
     53,483       (65 )     48,628       73  
Southern Dome
               (291 )             (652 )
     Plant inlet
(MMBtu/d)
     10,354               11,970          
     NGLs produced
(Bbls/d)
     375               429          
Bighorn and Fort Union(e)
 
(MMBtu/d)
     694,961       (2,970 )     670,543       164,136  
 
     
Nine Months Ended September 30,
  
     
2012
    
2011
  
     
Volume
    
Equity (Earnings)/Loss
    
Volume
    
Equity (Earnings)/Loss
  
Eagle Ford Gathering
           $ (21,082 )         $ (1,978 )
     Pipeline throughput(a) 
(MMBtu/d)
     260,212               13,026          
     NGLs produced(a) 
(Bbls/d)
     10,875               —          
Liberty Pipeline Group(c) 
(Bbls/d)
     20,172       311       888       60  
Webb Duval(b) 
(MMBtu/d)
     59,517       (255 )     48,705       257  
Southern Dome
               (692 )             (2,023 )
     Plant inlet
(MMBtu/d)
     9,245               11,630          
     NGLs produced
(Bbls/d)
     329               418          
Bighorn and Fort Union(e)
 
(MMBtu/d)
     742,937       111,740       595,302       162,302  
____________________________________
                                  
(a) For the three and nine months ended September 30, 2011, the volume has been recast from 58,295 (MMBtu/d), as previously stated, to show daily flow averaged over the 92 days and 273 days of the three and nine month periods, respectively, instead of the 63 days of physical flow.
 
 
(b) Net of NGLs produced at Copano’s Houston Central complex.
 
 
(c) For the three and nine months ended September 30, 2011, the volume has been recast from 4,252 (MMBtu/d), as previously stated, to show daily flow averaged over the 92 days and 273 days of the three and nine month periods, respectively, instead of the 57 days of physical flow.
 
 
(d) Net of intercompany volumes.
 
 
(e) Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated.
 
 
 
 
(4)
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 Copano’s firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn.
 
 
(5)
Corporate and other includes results attributable to Copano’s commodity risk management activities.
 
 
 
(6)
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.
 
 
 
(7)
“Service throughput” means the volume of natural gas delivered to Copano’s 100%-owned processing plants by third-party pipelines plus Copano’s “pipeline throughput,” which is the volume of natural gas transported or gathered through Copano’s pipelines.
 
 
(8)
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.
 

 
8 
 

 
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
  
UNAUDITED NON-GAAP FINANCIAL MEASURES
  
   
   
Three Months Ended
September 30,
    
Nine Months Ended
September 30,
  
             
   
2012
    
2011
    
2012
    
2011
  
Reconciliation of total segment gross margin to operating income (loss):
  
(In thousands)
  
Operating income (loss) 
   $ 43,185     $ (146,282 )   $ (53,969 )   $ (109,752 )
Add:  Operations and maintenance expenses  
     19,242       16,091       56,171       46,953  
Depreciation and amortization
     19,259       16,911       57,409       51,143  
Impairment
     -       5,000       28,744       5,000  
General and administrative expenses
    13,697       10,031       38,939       34,530  
Taxes other than income
    1,983       1,502       5,459       4,029  
Equity in (earnings) loss from unconsolidated affiliates
     (12,558 )     161,589       89,733       158,581  
Gain on sale of operating assets
     (9,716 )     -       (9,716 )     -  
Total segment gross margin  
   $ 75,092     $ 64,842     $ 212,770     $ 190,484  
                                 
Reconciliation of EBITDA, adjusted EBITDA and total distributable
                                
cash flow to net income (loss):
                                
Net income (loss) 
   $ 28,925     $ (157,736 )   $ (97,628 )   $ (163,565 )
Add:  Depreciation and amortization 
     19,259       16,911       57,409       51,143  
Interest and other financing costs
    13,797       11,080       42,823       34,450  
Provision for income taxes
    474       390       1,406       1,161  
EBITDA  
     62,455       (129,355 )     4,010       (76,811 )
Add:  Amortization of commodity derivative options  
     5,924       7,442       16,002       22,069  
Distributions from unconsolidated affiliates
    11,994       6,757       34,508       20,329  
Loss on refinancing of unsecured debt
     -       -       -       18,233  
Equity-based compensation
    3,223       2,093       7,575       9,184  
Equity in (earnings) loss from unconsolidated affiliates
    (12,558 )     161,589       89,733       158,581  
Unrealized loss (gain) from commodity risk management activities
     2,583       (2,332 )     (1,818 )     (2,695 )
Impairment
     -       5,000       28,744       5,000  
Other non-cash operating items
     (591 )     576       2,894       (272 )
Adjusted EBITDA  
     73,030       51,770       181,648       153,618  
Less:  Interest expense 
     (13,745 )     (11,029 )     (42,526 )     (33,623 )
Current income tax expense and other
     (419 )     (305 )     (1,166 )     (929 )
Maintenance capital expenditures
    (1,743 )     (3,510 )     (7,984 )     (11,111 )
Total distributable cash flow  
   $ 57,123     $ 36,926     $ 129,972     $ 107,955  
                                 
Actual quarterly distribution
   $ 46,087     $ 38,705                  
Total distributable cash flow coverage
    124 %     95 %                
 
 
9