Copano Energy Reports Second Quarter 2012 Results - Issues 2013 Guidance

HOUSTON, Aug. 8, 2012 /PRNewswire/ -- Copano Energy, L.L.C. (NASDAQ:   CPNO) today announced its financial results for the three months ended June 30, 2012.

Second Quarter 2012 Highlights:

  • Total distributable cash flow of $39.5 million, a 5% increase from second quarter 2011
  • Total segment gross margin of $72.9 million, a 12% increase from the prior year period
  • Adjusted EBITDA of $58.3 million, a 7% increase from the prior year period
  • Volumes gathered from the Eagle Ford Shale play averaged 490,000 MMBtu/d, a 277% increase from the prior year period
  • Texas segment NGL production of over 50,000 Bbls/d, an 86% increase from second quarter 2011

2013 Guidance:

  • Adjusted EBITDA forecasted to range from $300 million to $330 million
  • Total Distributable Cash Flow forecasted to range from $220 million to $240 million
  • Common unit distribution growth rate target of 7% to 9%

"Continued strong volume growth from the Eagle Ford Shale and increased volumes at our Saint Jo plant, combined with improving asset performance, led to increased financial results during the second quarter," said R. Bruce Northcutt, Copano's President and Chief Executive Officer.  "Our results also benefited from our strategy of transitioning to a more fee-based business, which has reduced the impact of the lower commodity price environment." 

"We are pleased with our progress on capital projects and look forward to achieving the full benefits of our Eagle Ford strategy, which will drive cash flow and distribution growth in 2013.  At the same time, we have begun to focus on new long-term growth opportunities to create additional value for Copano unitholders," Northcutt added.

Second Quarter Financial Results

Total distributable cash flow increased 5% from a year ago, to $39.5 million for the second quarter of 2012, and 19% from the first 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,
  • volumes processed at the Lake Charles plant in Louisiana, and
  • lower maintenance capital expenditures.

These benefits were partially offset by lower natural gas liquids (NGL) prices and higher interest and operating expenses.

Second-quarter 2012 total distributable cash flow represents 93% coverage of the second-quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.

Revenue for the second quarter of 2012 decreased 8% from the second quarter of 2011 to $317.3 million, and 6% from the first quarter of 2012.  Total segment gross margin increased 12% from both the second quarter of 2011 and first quarter of 2012 to $72.9 million.  Adjusted EBITDA increased 7% from the second quarter of 2011, to $58.3 million and 16% from first quarter of 2012.  Net income to common was $12.2 million for the second quarter of 2012, compared to net loss of $17.4 million for the second quarter of 2011.

Corporate and other activities, which include Copano's commodity risk management efforts, contributed a gain of $3.4 million for the second quarter of 2012 compared to a loss of $10.3 million for the second quarter of 2011 and a loss of $5.1 million for the first quarter of 2012. 

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 6 of this news release.

Second Quarter Operating Results by Segment

Texas

Segment gross margin for Texas increased 6% from the second quarter of 2011 to $49.1 million, and increased 8% from the first 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 lower NGL prices and a decline in lean gas volumes, which were displaced by rich gas volumes at the Houston Central complex.  Also, the Lake Charles plant, which contributed $2.5 million to Texas gross margin for the second quarter of 2012, did not operate during the prior-year period. 

During the second quarter of 2012, the Texas segment provided gathering and processing services for an average of 924,465 MMBtu/d of natural gas, an increase of 39% from the second quarter of 2011.  The Texas segment gathered an average of 566,388 MMBtu/d of natural gas, an increase of 28% over the second 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 834,846 MMBtu/d during the second quarter of 2012, an increase of 42% over the second quarter of 2011 primarily due to increased volumes from the north Barnett Shale Combo play and at the Lake Charles plant.  Second-quarter NGL production averaged 50,146 Bbls/d at Copano-owned plants and third-party plants, an increase of 86% from the second quarter of 2011 and 42% from the first quarter of 2012, 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 and the Lake Charles plant in Louisiana.

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 252,912 MMBtu/d during the second 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 second quarter of 2012, equity earnings and distributions from Eagle Ford Gathering totaled $9.8 million and $4.8 million, respectively.

Oklahoma

Segment gross margin for Oklahoma was $20.2 million for the second quarter of 2012, a decrease of 30% compared to the second quarter of last year and 17% from the first quarter of 2012.  The year-over-year decrease resulted primarily from a decrease of 39% in realized margins on service throughput compared to the second quarter of 2011 ($0.68 per MMBtu in 2012 compared to $1.11 per MMBtu in 2011) due to lower NGL and natural gas prices.  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 324,915 MMBtu/d of natural gas, an increase of 14% compared to the second quarter of 2011, due primarily to lean gas from the Woodford Shale area, which increased 46% compared to the second quarter of 2011.  Volumes processed at wholly-owned and third-party plants in Oklahoma were flat compared to the second quarter of 2011, averaging 158,016 MMBtu/d.  Second quarter NGL production at Copano-owned plants and third-party plants averaged 17,028 Bbls/d, a decrease of 2% from the second quarter of 2011.

Rocky Mountains

Segment gross margin for the Rocky Mountains segment totaled $0.2 million in the second quarter of 2012 compared to $0.8 million for the second quarter of 2011 and $0.4 million for the first 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."

Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 40% to 747,009 MMBtu/d in the second quarter of 2012 as compared to 533,329 MMBtu/d in the second 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, the increase did not have a material impact on Copano's equity earnings or distributions.  For the second quarter of 2012, combined equity earnings for Bighorn and Fort Union totaled $2.6 million, compared to $0.6 million for the same period in 2011.  Combined distributions from Bighorn and Fort Union totaled $7.3 million in the second quarter of 2012, compared to $6.3 million in the second quarter of last year.

Cash Distributions

On July 11, 2012, Copano announced its second quarter 2012 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units.  This distribution is unchanged from the first quarter of 2012 and will be paid on August 9, 2012 to common unitholders of record at the close of business on July 31, 2012.

2013 Guidance

Copano announced today its forecast for certain financial items for 2013, as outlined in the table below:

($ in millions)

Calendar 2013

Adjusted EBITDA

$300 to $330

Total distributable cash flow

$220 to $240

Common unit distribution growth rate target(1)

7% to 9%

Quarterly common unit distribution coverage target

100% to 115%

Fee-based margin(2)

55% to 60%

Capital expenditures:


     Expansion

$250 to $300

     Maintenance

$13 to $18

___________________________

(1)  Based on annualized fourth quarter 2013 declared distribution

(2)  Represents fee-based component of our total segment gross margin and our share of gross margin from our unconsolidated affiliates

The above forecasted amounts are based on various assumptions, which include an average natural gas price of $3.80 per MMBtu, weighted-average Mont Belvieu and Conway NGL prices of $33.16 per barrel and $29.34 per barrel, respectively, and an average NYMEX crude price of $90.34 per barrel.  Additionally, for the third and fourth quarters of 2013, Copano assumes no conversion of its preferred units then outstanding and payment of cash rather than in-kind preferred unit distributions.

Additional assumptions include, among others, timely and on-budget completion of Copano's announced expansion capital projects, forecasted operational volumes from existing operations and expansion capital projects, Copano's existing contract portfolio and outstanding commodity hedge portfolio, receipt of volume deficiency payments under certain contracts, consistent operations at third-party facilities and timely completion of expansions at third-party facilities that impact Copano's operations, estimated interest rates, and budgeted operations and maintenance and general and administrative costs. Management will issue updated 2013 guidance in subsequent earnings announcements only if revised expectations fall outside the ranges set forth above.

Management does not develop detailed forecasts for certain items, including GAAP revenues, depreciation, amortization and non-cash changes in derivatives, and therefore is unable to provide forecasted net income, a comparable GAAP measure, for the period presented. 

With respect to the third and fourth quarters of 2012, management expects to continue to provide quarterly gross margin trends and any material updates to full-year 2012 capital expenditures and expense guidance.

Conference Call Information

Copano will hold a conference call on August 9, 2012 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) to discuss its second quarter 2012 financial results.  To participate in the call, dial (480) 629-9645 and ask for the Copano call at least 10 minutes prior to the start time, or access it live over the internet at 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 August 16, 2012 by calling (303) 590-3030 and using the pass code 4551423#.

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, Wyoming and Louisiana.  More information is available at 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 obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production; producers' ability to drill and successfully complete and attach new natural gas supplies; the NGL content of new gas supplies; Copano's ability to access or construct new processing, fractionation and transportation capacity; the availability of downstream transportation and other facilities for natural gas and NGLs; mechanical failures and other operational risks affecting the performance of Copano's processing plants and other facilities, higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano's quarterly and annual reports filed with the Securities and Exchange Commission.



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



financial statements follow –

 

 

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS









Three Months Ended

June 30,



Six Months Ended

June 30,











2012


2011



2012


2011





















(In thousands, except per unit information)

Revenue:















Natural gas sales 


$

69,993


$

123,928



$

156,205


$

227,723


Natural gas liquids sales 



188,780



180,758




383,967



329,759


Transportation, compression and processing fees 



43,241



27,898




83,080



52,369


Condensate and other 



15,289



13,472




31,279



26,130



Total revenue 



317,303



346,056




654,531



635,981

















Costs and expenses:















Cost of natural gas and natural gas liquids (1)



238,482



274,398




504,433



498,128


Transportation (1)



5,971



6,362




12,420



12,211


Operations and maintenance 



18,287



15,763




36,929



30,862


Depreciation and amortization



19,062



17,363




38,150



34,232


Impairment



-



-




28,744



-


General and administrative 



10,298



11,901




25,242



24,499


Taxes other than income 



2,110



1,397




3,476



2,527


Equity in (earnings) loss from unconsolidated affiliates 



(12,437)



(1,306)




102,291



(3,008)



Total costs and expenses 



281,773



325,878




751,685



599,451

















Operating income (loss)



35,530



20,178




(97,154)



36,530

Other income (expense):















Interest and other income 



521



8




559



15


Loss on refinancing of unsecured debt 



-



(18,233)




-



(18,233)


Interest and other financing costs 



(14,602)



(11,454)




(29,026)



(23,370)

Income (loss) before income taxes



21,449



(9,501)




(125,621)



(5,058)

Provision for income taxes 



(331)



140




(932)



(771)

Net income (loss)



21,118



(9,361)




(126,553)



(5,829)

Preferred unit distributions



(8,915)



(8,076)




(17,613)



(15,956)

Net income (loss) to common units


$

12,203


$

(17,437)



$

(144,166)


$

(21,785)

















Basic net income (loss) per common unit:















Net income (loss) per common unit


$

0.17


$

(0.26)



$

(2.01)


$

(0.33)


Weighted average number of common units 



72,300



66,143




71,630



66,065

















Diluted net income (loss) per common unit:















Net income (loss) per common unit


$

0.14


$

(0.26)



$

(2.01)


$

(0.33)


Weighted average number of common units 



85,176



66,143




71,630



66,065

































Distributions declared per common unit


$

0.575


$

0.575



$

1.150


$

1.150

____________














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

 

 

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS














Six Months Ended June 30,














2012


2011












Cash Flows From Operating Activities:



(In thousands)


Net loss


$

(126,553)



$

(5,829)


Adjustments to reconcile net loss to net cash provided by operating activities:










Depreciation and amortization



38,150




34,232



Impairment



28,744




-



Amortization of debt issue costs



1,978




1,949



Equity in loss (income) from unconsolidated affiliates



102,291




(3,008)



Distributions from unconsolidated affiliates



20,618




12,323



Loss on refinancing of unsecured debt



-




18,233



Non-cash gain on risk management activities, net 



(6,021)




(1,536)



Equity-based compensation



2,314




5,340



Deferred tax provision



185




168



Other non-cash items



346




(10)



Changes in assets and liabilities, net of acquisitions:











Accounts receivable



24,756




(15,637)




Prepayments and other current assets



2,733




2,110




Risk management activities



6,105




5,455




Accounts payable



(45,705)




21,498




Other current liabilities



3,621




718





Net cash provided by operating activities



53,562




76,006













Cash Flows From Investing Activities:









Additions to property, plant and equipment



(142,465)




(98,289)


Additions to intangible assets



(2,740)




(4,140)


Acquisitions



-




(16,084)


Investments in unconsolidated affiliates



(34,165)




(65,027)


Distributions from unconsolidated affiliates



1,896




1,249


Escrow cash



-




6


Proceeds from sale of assets



178




141


Other



3,366




(185)





Net cash used in investing activities 



(173,930)




(182,329)













Cash Flows From Financing Activities:









Proceeds from long-term debt



330,375




605,000


Repayment of long-term debt



(317,000)




(392,665)


Payments of premiums and expenses on redemption of unsecured debt



-




(14,572)


Deferred financing costs



(3,434)




(15,670)


Distributions to unitholders



(84,150)




(76,571)


Proceeds from public offering of common units, net of underwriting discounts










and commissions of $7,590



188,083




-


Equity offering costs



(360)




(4)


Proceeds from option exercises 



888




2,431





Net cash provided by financing activities



114,402




107,949













Net (decrease) increase in cash and cash equivalents



(5,966)




1,626

Cash and cash equivalents, beginning of year



56,962




59,930

Cash and cash equivalents, end of period


$

50,996



$

61,556