Copano Energy Reports Third Quarter 2009 Results
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HOUSTON, Nov. 4 TX-Copano-Energy
HOUSTON, Nov. 4 /PRNewswire-FirstCall/ -- Copano Energy, L.L.C. (Nasdaq: CPNO) today announced its financial results for the three and nine months ended September 30, 2009.
"Despite a difficult environment for our customers, we are pleased to report full coverage of our unitholder distribution for the nineteenth consecutive quarter," said John Eckel, Copano Energy's Chairman and Chief Executive Officer.
Third Quarter Financial Results
Revenue for the third quarter of 2009 decreased 53% to $189.5 million compared with $402.9 million for the third quarter of 2008. Total segment gross margin decreased 13% to $53.4 million for the third quarter of 2009 from $61.4 million for the same period a year ago.
Adjusted EBITDA for the third quarter of 2009 decreased 5% to $41.2 million compared with $43.5 million for the third quarter of 2008. Adjusted EBITDA is earnings before interest, taxes, depreciation and amortization, adjusted to include Copano's share of depreciation, amortization and interest costs attributable to its unconsolidated affiliates. Non-cash charges incurred during the third quarter of 2009 that were not added back in determining adjusted EBITDA include amortization expense of $9.2 million related to the option component of Copano's risk management portfolio.
Total distributable cash flow for the third quarter of 2009 totaled $33.4 million compared to $38.6 million for the third quarter of 2008. Third quarter 2009 total distributable cash flow represents 105% coverage of the third quarter 2009 distribution of $0.575 per unit.
Net income decreased by 57% to $3.7 million, or $0.06 per unit on a diluted basis, for the third quarter of 2009 compared to net income of $8.7 million, or $0.15 per unit on a diluted basis, for the third quarter of 2008. The drivers of Copano's net income for the third quarter of 2009 compared to the third quarter of 2008 included:
- a decrease in total segment gross margin of $7.9 million consisting of a $29.9 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 54% in the Conway index and 49% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $22.0 million from Copano's commodity risk management activities; and
- an increase in depreciation and amortization expenses of $1.9 million primarily related to expanded operations in north Texas;
partially offset by:
- a decrease in operations and maintenance expenses of $2.0 million and general and administrative expenses of $1.8 million primarily related to successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees;
- an increase of $0.4 million in equity in earnings of unconsolidated affiliates; and
- an increase in interest and other income of $0.7 million.
Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures that are defined and reconciled to the most directly comparable GAAP measures at the end of this news release.
Third Quarter Operating Results by Segment
Copano manages its business in three geographical operating segments: Oklahoma, Texas and the Rocky Mountains.
Oklahoma
The Oklahoma segment provides midstream natural gas services in central and east Oklahoma. During the third quarter of 2009, segment gross margin for the Oklahoma segment decreased 45% to $18.3 million compared to $33.1 million for the third quarter of 2008. The decrease resulted primarily from a 49% decline in realized margins on service throughput from the third quarter of 2008 ($0.76 per MMBtu in 2009 compared with $1.48 per MMBtu in 2008), reflecting lower NGL and natural gas prices. During the third quarter of 2009, NGL prices based on Conway index prices and Copano's weighted average product production mix averaged $27.62 per barrel compared with $59.42 per barrel during the third quarter of last year, a decrease of $31.80, or 54%. During the third quarter of 2009, natural gas prices based on CenterPoint East index prices averaged $2.98 per MMBtu compared with $8.41 per MMBtu during the third quarter of 2008, a decrease of $5.43, or 65%.
The decrease in segment gross margin for the Oklahoma segment was partially offset by increased service throughput and processing volumes. The Oklahoma segment gathered an average of 260,296 MMBtu/d of natural gas, processed an average of 166,884 MMBtu/d of natural gas and produced an average of 16,474 Bbls/d of NGLs at its plants and third-party plants during the third quarter of 2009, representing increases of 7%, 6% and 8%, respectively, compared with the third quarter of 2008. The increase in throughput is primarily attributable to the residual effects of drilling activity initiated during the favorable pricing environment in early 2008. During the third quarter of last year, the Oklahoma segment gathered an average of 243,000 MMBtu/d of natural gas, processed an average of 158,047 MMBtu/d of natural gas and produced an average of 15,238 Bbls/d of NGLs.
Texas
The Texas segment provides midstream natural gas services in Texas and also owns a processing plant in southwest Louisiana.
Segment gross margin for the Texas segment decreased approximately 35% in the third quarter of 2009 to $26.9 million compared to $41.4 million for the third quarter of 2008. The decrease resulted primarily from a 28% decline in realized margins on service throughput from the third quarter of 2008 ($0.48 per MMBtu in 2009 compared with $0.67 per MMBtu in 2008), reflecting lower NGL prices. During the third quarter of 2009, NGL prices based on Mt. Belvieu index prices and Copano's weighted average product production mix averaged $35.09 per barrel compared with $69.12 per barrel during the third quarter of 2008, a decrease of $34.03, or 49%.
The decrease in segment gross margin for the Texas segment was also attributable to decreased service throughput and processing volumes. During the third quarter of 2009, the Texas segment provided gathering, transportation and processing services for an average of 613,234 MMBtu/d of natural gas compared with 666,686 MMBtu/d for the third quarter of 2008, a decrease of 8%. The Texas segment gathered an average of 296,003 MMBtu/d of natural gas, processed an average of 543,994 MMBtu/d of natural gas at its plants and third-party plants and produced an average of 18,197 Bbls/d of NGLs at its plants and third-party plants during the third quarter of 2009, representing decreases of 2% and 9%, and an increase of 7%, respectively, as compared with the third quarter of last year. During the third quarter of 2008, the Texas segment gathered an average of 301,279 MMBtu/d of natural gas, processed an average of 596,225 MMBtu/d of natural gas and produced an average of 16,957 Bbls/d of NGLs. Volumes originating from the Texas segment and delivered to the plant decreased approximately 7% from the third quarter of last year whereas natural gas delivered to the plant and originated from sources other than the Texas segment decreased approximately 23% from the third quarter of 2008.
Rocky Mountains
The Rocky Mountains segment provides services to producers in Wyoming's Powder River Basin and owns managing member interests in Bighorn Gas Gathering of 51% and in Fort Union Gas Gathering of 37.04%.
Segment gross margin for the Rocky Mountains segment was $0.6 million for the third quarter of 2009 compared with $1.3 million for the same period in 2008. Producer services throughput, which represents volumes purchased for resale, volumes gathered using firm capacity gathering agreements with Fort Union and volumes transported under firm capacity transportation agreements with Wyoming Interstate Gas Company (WIC), or using additional capacity that Copano obtains on WIC, averaged 157,362 MMBtu/d for the third quarter of 2009, as compared to 230,859 MMBtu/d for the same period in 2008.
The decrease in segment gross margin was the result of lower volumes and unit margins primarily due to a continuing weak pricing environment in the Rocky Mountains creating disincentives for producers to continue drilling programs or to initiate de-watering programs on wells previously drilled. The Rocky Mountains segment results do not include the financial results and volumes associated with Copano's interests in Bighorn and Fort Union, which are accounted for under the equity method of accounting and are shown under "Equity in earnings from unconsolidated affiliates." Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 1% in the third quarter of 2009 as compared with the third quarter of 2008. Average pipeline throughput for Bighorn and Fort Union for the third quarter of 2009 totaled 190,229 MMBtu/d and 761,897 MMBtu/d, respectively, as compared to 211,353 MMBtu/d and 735,131 MMBtu/d, respectively, for the third quarter of 2008. Amine treating facilities placed in service during the fourth quarter of 2008 contributed to Fort Union's increase in average pipeline throughput.
Corporate and Other
Corporate and other gross margin includes Copano's commodity risk management activities. These activities produced a gain of $7.6 million for the third quarter of 2009 compared to a loss of $14.4 million for the third quarter of 2008. The gain for the third quarter of 2009 included $16.4 million of net cash settlements received for expired commodity derivative instruments and $0.4 million of unrealized mark-to-market gains on undesignated economic hedges offset by $9.2 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio. The third quarter 2008 loss included $7.0 million of net cash settlements paid for expired commodity derivative instruments and $8.4 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio offset by $1.0 million of unrealized mark-to-market gains on undesignated economic hedges.
Year-to-Date Financial Results
Revenue for the first nine months of 2009 decreased 52% to $570.8 million compared to $1.2 billion for the same period of last year. Total segment gross margin decreased 18% to $157.5 million for the nine months ended September 30, 2009 from $192.3 million for the same period in 2008. For the nine months ended September 30, 2009, total segment gross margin included a net gain of $34.5 million related to Copano's risk management activities, comprised of $62.3 million of net cash settlements received on expired commodity derivative instruments offset by $27.7 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio and $0.1 million of unrealized mark-to-market losses on undesignated economic hedges. Total segment gross margin for the nine months ended September 30, 2008 included a net loss of $49.7 million related to Copano's risk management activities comprised of $19.4 million of net cash settlements paid on expired commodity derivative instruments, $24.5 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio and $5.8 million of unrealized mark-to-market losses on undesignated economic hedges.
Adjusted EBITDA decreased 18% to $120.8 million for the first nine months of 2009 compared to $146.7 million for the same period of last year. Total distributable cash flow decreased 22% to $101.4 million for the nine months ended September 30, 2009 compared to $129.2 million for the same period of 2008.
Net income decreased by 66% to $15.7 million, or $0.27 per unit on a diluted basis, for the nine months ended September 30, 2009 compared to net income of $46.4 million, or $0.80 per unit on a diluted basis, for the nine months ended September 30, 2008. The drivers of net income for 2009 compared to 2008 included:
- a decrease in total segment gross margin of $34.8 million consisting of a $119.0 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 57% in the Conway index and 54% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $84.2 million from commodity risk management activities;
- an increase in depreciation and amortization expenses of $4.1 million primarily related to expanded operations in north Texas;
- a decrease of $1.3 million in equity in earnings of unconsolidated affiliates; and
- a decrease in discontinued operations and income taxes of $1.0 million;
- partially offset by:
- a decrease in general and administrative expenses of $4.6 million and operations and maintenance expenses of $1.0 million primarily related to successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees;
- a gain of $3.9 million related to the repurchase and retirement of $18.2 million aggregate principal amount of 7.75% senior unsecured notes due 2018 at market prices averaging 78% of the face amount of the notes; and
- a decrease of $1.0 million in interest expense as a result of (i) a decrease of non-cash mark-to-market charges on interest rate swaps of $5.2 million offset by (ii) an increase in interest expense of $4.2 million as a result of increased average outstanding borrowings slightly offset by lower average interest rates between the periods.
Cash Distributions
On October 14, 2009, Copano announced a third quarter 2009 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 equal to Copano's distribution of $0.575 per unit for the second quarter of 2009 and is payable on November 12, 2009 to common unitholders of record at the close of business on November 2, 2009.
Conference Call Information
Copano will hold a conference call to discuss its third quarter 2009 financial results and recent developments on Thursday, November 5, 2009 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9869 and ask for the Copano call 10 minutes prior to the start time, or access it live over the internet at www.copanoenergy.com on the "Investor Overview" page of the "Investor Relations" section of Copano's website.
A replay of the audio webcast will be available shortly after the call on Copano's website. Additionally, a telephonic replay will be available through November 12, 2009 by calling (303) 590-3030 and using the pass code 4175140#.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow. 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, operating income, income from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano uses non-GAAP financial measures as measures of its core profitability or to assess the financial performance of its assets. Copano believes that investors benefit from having access to the same financial measures that its management uses in evaluating Copano's liquidity position or financial performance.
Copano defines segment gross margin as an operating segment's revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs purchased, cost of crude oil purchased and costs for transportation of volumes. Total segment gross margin is the sum of the operating segment gross margins and the results of Copano's risk management activities that are included in Corporate and other. Copano views total segment gross margin as an important performance measure of the core profitability of its operations. Segment gross margin allows Copano's senior management to compare volume and price performance of the segments and to more easily identify operational or other issues within a segment. The GAAP measure most directly comparable to total segment gross margin is operating income.
Copano defines EBITDA as income (loss) from continuing operations plus interest and other financing costs, provision for income taxes and depreciation, amortization and impairment expense. Because a portion of Copano's net income (loss) is attributable to equity in earnings (loss) from its unconsolidated affiliates, including Bighorn, Fort Union, Webb/Duval Gatherers (Webb Duval) and Southern Dome, LLC (Southern Dome), Copano calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, Copano determines adjusted EBITDA by adding to EBITDA (i) the amortization expense attributable to the difference between Copano's carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate's depreciation and amortization expense which is proportional to Copano's ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate's interest and other financing costs which is proportional to Copano's ownership interest in that unconsolidated affiliate. External users of Copano's financial statements such as investors, commercial banks and research analysts use EBITDA or adjusted EBITDA, and Copano's management uses adjusted EBITDA as a supplemental financial measure to assess:
- the financial performance of Copano's assets without regard to financing methods, capital structure or historical cost basis;
- the ability of Copano's assets to generate cash sufficient to pay interest costs and support indebtedness;
- Copano's operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
- the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to Copano's lenders and used to compute financial covenants under its revolving credit facility. Neither EBITDA nor adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP. Copano's EBITDA or adjusted EBITDA may not be comparable to EBITDA, adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA or adjusted EBITDA in the same manner as Copano does. Copano has reconciled EBITDA and adjusted EBITDA to net income and cash flows from operating activities.
Copano defines total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense relating to the option component of Copano's risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v) the subtraction of equity in earnings from unconsolidated affiliates; and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and Copano's line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of Copano's assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.
Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by Copano (prior to the establishment of any retained cash reserves by its Board of Directors) to the cash distributions Copano expects to pay its unitholders, and it also correlates with the metrics of Copano's existing debt covenants. Using total distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Total distributable cash flow is also an important non-GAAP financial measure for unitholders because it serves as an indicator of Copano's success in providing a cash return on investment-- specifically, whether or not Copano is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Total distributable cash flow is also used by industry analysts with respect to publicly traded partnerships and limited liability companies because the market value of such an entities' equity securities is significantly influenced by the amount of cash they can distribute to unitholders. The GAAP measure most directly comparable to total distributable cash flow is net income. Total distributable cash flow should not be considered an alternative to net income, income from continuing operations, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.
Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Oklahoma, Texas, Wyoming and Louisiana.
This news release may include "forward-looking statements" as defined by the Securities and Exchange Commission. These statements reflect certain assumptions based on management's experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. These statements include, but are not limited to, statements with respect to future distributions. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Copano's control, which may cause Copano's actual results to differ materially from those implied or expressed by the forward-looking statements. These risks include an inability to obtain new sources of natural gas supplies, the loss of key producers that supply natural gas to Copano, key customers reducing the volume of natural gas and NGLs they purchase from Copano, a decline in the price and market demand for natural gas and NGLs, the incurrence of significant costs and liabilities in the future resulting from Copano's failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment and other factors detailed in Copano's Securities and Exchange Commission filings.
Contacts: Carl Luna, SVP & CFO
Copano Energy, L.L.C.
713-621-9547
Jack Lascar / jlascar@drg-e.com
Anne Pearson / apearson@drg-e.com
DRG&E / 713-529-6600
- financial statements to follow -
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
-------------- ---------------
2009 2008 2009 2008
---- ---- ---- ----
(In thousands, except per unit information)
Revenue:
Natural gas sales $66,747 $204,187 $226,243 $620,074
Natural gas liquids
sales 99,098 174,867 271,392 507,979
Transportation,
compression and
processing fees 13,926 13,772 42,838 42,896
Condensate and other 9,760 10,044 30,319 36,582
----- ------ ------ ------
Total revenue 189,531 402,870 570,792 1,207,531
------- ------- ------- ---------
Costs and expenses:
Cost of natural gas
and natural gas
liquids (1) 129,617 332,346 395,114 999,580
Transportation (1) 6,484 9,151 18,211 15,688
Operations and
maintenance 13,202 15,211 38,764 39,770
Depreciation and
amortization 14,575 12,700 41,071 36,929
General and
administrative 9,200 11,042 29,246 33,828
Taxes other than
income 836 723 2,349 2,193
Equity in earnings
from unconsolidated
affiliates (2,529) (2,170) (6,112) (7,354)
------ ------ ------ ------
Total costs and
expenses 171,385 379,003 518,643 1,120,634
------- ------- ------- ---------
Operating income 18,146 23,867 52,149 86,897
Interest and other
income 1,065 357 1,119 1,091
Gain on retirement
of unsecured debt - - 3,939 -
Interest and other
financing costs (15,440) (15,470) (41,889) (42,939)
------- ------- ------- -------
Income before income
taxes 3,771 8,754 15,318 45,049
Provision for income
taxes (304) (197) (1,039) (846)
---- ---- ------ ----
Income from
continuing
operations 3,467 8,557 14,279 44,203
Discontinued
operations, net of
tax 262 166 1,393 2,224
--- --- ----- -----
Net income $3,729 $8,723 $15,672 $46,427
====== ====== ======= =======
Basic net income per
common unit:
Income per common
unit from continuing
operations $0.06 $0.18 $0.26 $0.93
Income per common
unit from
discontinued
operations 0.01 $0.00 $0.03 $0.04
----- ----- -----
Net income $0.07 $0.18 $0.29 $0.97
===== ===== ===== =====
Weighted average
number of common
units 54,565 47,868 54,313 47,640
Diluted net income
per common unit:
Income per common
unit from
continuing
operations $0.06 $0.15 $0.25 $0.76
Income per common
unit from
discontinued
operations 0.00 0.00 0.02 0.04
---- ---- ----
Net income $0.06 $0.15 $0.27 $0.80
===== ===== ===== =====
Weighted average
number of common
units 58,036 57,939 57,953 57,891
(1) Exclusive of operations and maintenance and depreciation and
amortization shown separately below.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
---------------
2009 2008
---- ----
(In thousands)
Cash Flows From Operating Activities:
Net income $15,672 $46,427
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 41,628 37,092
Amortization of debt issue costs 3,060 2,552
Equity in earnings from unconsolidated affiliates(6,112) (7,354)
Distributions from unconsolidated affiliates 18,333 18,387
Gain on retirement of unsecured debt (3,939) -
Non-cash (gain) loss on risk management
portfolio, net (1,443) 9,485
Equity-based compensation 6,692 3,542
Deferred tax provision 538 294
Other noncash items 202 (132)
Changes in assets and liabilities:
Accounts receivable 14,857 6,879
Prepayments and other current assets 1,196 655
Risk management activities 23,462 (35,397)
Accounts payable (12,034) 21,259
Other current liabilities (1,363) (2,468)
------- -------
Net cash provided by operating activities 100,749 101,221
------- -------
Cash Flows From Investing Activities:
Additions to property, plant and equipment (51,540) (115,292)
Additions to intangible assets (1,756) (4,710)
Acquisitions (6,003) (83)
Investment in unconsolidated affiliates (3,240) (25,623)
Distributions from unconsolidated affiliates 3,191 1,971
Escrow cash - (1,856)
Other (1,358) (1,232)
------- -------
Net cash used in investing activities (60,706) (146,825)
-------- -------
Cash Flows From Financing Activities:
Proceeds from long-term debt 50,000 539,000
Repayment of long-term debt (10,000) (314,000)
Retirement of unsecured debt (14,286) -
Deferred financing costs - (6,670)
Distributions to unitholders (94,217) (76,623)
Capital contributions from pre-IPO investors - 4,103
Equity offering costs - (47)
Proceeds from option exercises 154 1,001
--- -----
Net cash (used in) provided by financing
activities (68,349) 146,764
-------- -------
Net (decrease) increase in cash and
cash equivalents (28,306) 101,160
Cash and cash equivalents, beginning of year 63,684 72,665
------ ------
Cash and cash equivalents, end of period $35,378 $173,825
======= ========
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
As of
-----
September December
30, 31,
2009 2008
--------- --------
(In thousands, except
unit information)
ASSETS
Current assets:
Cash and cash equivalents $35,378 $63,684
Accounts receivable, net 81,963 96,028
Risk management assets 47,128 76,440
Prepayments and other current assets 3,688 4,891
Discontinued operations 5,608 5,465
----- -----
Total current assets 173,765 246,508
------- -------
Property, plant and equipment, net 834,756 819,099
Intangible assets, net 191,842 198,440
Investment in unconsolidated affiliates 627,068 640,598
Escrow cash 1,858 1,858
Risk management assets 31,346 82,892
Other assets, net 21,924 24,270
------ ------
Total assets $1,882,559 $2,013,665
========== ==========
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Accounts payable $89,285 $103,849
Accrued interest 9,549 11,904
Accrued tax liability 495 784
Risk management liabilities 8,019 6,272
Other current liabilities 10,222 16,787
Discontinued operations 384 -
--- ---
Total current liabilities 117,954 139,596
------- -------
Long-term debt (includes $647 and $704 bond
premium as of September 30, 2009 and
December 31, 2008, respectively) 842,837 821,119
Deferred tax provision 2,256 1,718
Risk management and other noncurrent liabilities 11,966 13,274
Members' capital:
Common units, no par value, 54,601,458 and
53,965,288 units issued and outstanding
as of September 30, 2009 and
December 31, 2008, respectively 878,994 865,343
Class C units, no par value, 0 units and
394,853 units issued and outstanding as
of September 30, 2009 and December 31, 2008,
respectively - 13,497
Class D units, no par value, 3,245,817 units
issued and outstanding as of September 30,
2009 and December 31, 2008 112,454 112,454
Paid-in capital 41,168 33,734
Accumulated deficit (133,900) (54,696)
Accumulated other comprehensive income 8,830 67,626
----- ------
907,546 1,037,958
------- ---------
Total liabilities and members' capital $1,882,559 $2,013,665
========== ==========
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
OPERATING STATISTICS
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
-------------- ---------------
2009 2008 2009 2008
---- ---- ---- ----
($in thousands)
Total segment gross
margin(1) (2) $53,430 $61,373 $157,467 $192,263
Operations and
maintenance expenses(2) 13,202 15,211 38,764 39,770
Depreciation and
amortization(2) 14,575 12,700 41,071 36,929
General and
administrative expenses 9,200 11,042 29,246 33,828
Taxes other than income 836 723 2,349 2,193
Equity in earnings from
unconsolidated affiliates (2,529) (2,170) (6,112) (7,354)
------ ------ ------ ------
Operating income(2) 18,146 23,867 52,149 86,897
Gain on retirement
of unsecured debt - - 3,939 -
Interest and other
financing costs, net (14,375) (15,113) (40,770) (41,848)
Provision for income
taxes (304) (197) (1,039) (846)
Discontinued operations,
net of tax 262 166 1,393 2,224
--- --- ----- -----
Net income $3,729 $8,723 $15,672 $46,427
====== ====== ======= =======
Total segment gross
margin:
Oklahoma(2) $18,284 $33,132 $50,058 $115,052
Texas 26,875 41,392 70,775 123,467
Rocky Mountains 634 1,257 2,144 3,438
--- ----- ----- -----
Segment gross
margin(2) 45,793 75,781 122,977 241,957
Corporate and
other(3) 7,637 (14,408) 34,490 (49,694)
----- ------- ------ -------
Total segment
gross margin(1) (2) $53,430 $61,373 $157,467 $192,263
======= ======= ======== ========
Segment gross margin
per unit:
Oklahoma:
Service throughput
($/MMBtu) (2) (4) $0.76 $1.48 $0.69 $1.81
Texas:
Service throughput
($/MMBtu) (5) $0.48 $0.67 $0.41 $0.65
Rocky Mountains:
Producer services
throughput
($/MMBtu) (6) $0.03 $0.06 $0.04 $0.05
Volumes:
Oklahoma:(4) (7)
Service throughput
(MMBtu/d) 260,296 243,000 266,306 231,358
Plant inlet
throughput
(MMBtu/d) 166,884 158,047 164,741 154,708
NGLs produced
(Bbls/d) 16,474 15,238 15,928 15,083
Texas: (5) (8)
Service throughput
(MMBtu/d) 613,234 666,686 629,367 688,694
Pipeline throughput
(MMBtu/d) 296,003 301,279 296,621 314,740
Plant inlet volumes
(MMBtu/d) 543,994 596,225 553,876 610,470
NGLs produced
(Bbls/d) 18,197 16,957 17,846 17,584
Rocky Mountains:
Producer services
throughput
(MMBtu/d)(6) 157,362 230,859 168,168 229,038
Capital Expenditures:
Maintenance capital
expenditures $1,886 $2,675 $7,932 $8,828
Expansion capital
expenditures 17,283 45,928 42,119 128,593
------ ------ ------ -------
Total capital
expenditures $19,169 $48,603 $50,051 $137,421
======= ======= ======= ========
Operations and
maintenance expenses:
Oklahoma(2) $6,111 $6,170 $17,335 $17,860
Texas 7,089 9,041 21,423 21,910
Rocky Mountains 2 - 6 -
--- --- --- ---
Total operations
and maintenance
expenses $13,202 $15,211 $38,764 $39,770
======= ======= ======= =======
- Total segment gross margin is a non-GAAP financial measure. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read "Non-GAAP Financial Measures."
- Excludes results attributable to Copano's crude oil pipeline and related assets as these amounts are shown under the caption "discontinued operations."
- Corporate and other includes results attributable to Copano's commodity risk management activities.
- Excludes volumes associated with Copano's interest in Southern Dome. For the three months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,857 MMBtu/d and NGLs produced averaged 523 Bbls/d. For the three months ended September 30, 2008, plant inlet volumes for Southern Dome averaged 11,557 MMBtu/d and NGLs produced averaged 389 Bbls/d. For the nine months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,304 MMBtu/d and NGLs produced averaged 490 Bbls/d. For the nine months ended September 30, 2008, plant inlet volumes for Southern Dome averaged 10,503 MMBtu/d and NGLs produced averaged 387 Bbls/d
- Excludes volumes associated with Copano's interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 72,985 MMBtu/d and 97,906 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Gross volumes transported by Webb Duval, net of intercompany volumes, were 82,001 MMBtu/d and 91,047 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively.
- Producers services throughput consists of volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union and volumes transported using firm capacity agreements with WIC. Excludes results and volumes associated with Copano's interests in Bighorn and Fort Union. Volumes gathered by Bighorn were 190,229 MMBtu/d and 211,353 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Volumes gathered by Fort Union were 761,897 MMBtu/d and 735,131 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Volumes gathered by Bighorn were 192,500 MMBtu/d and 215,568 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively. Volumes gathered by Fort Union were 786,908 MMBtu/d and 712,791 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively.
- 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 September 30, 2009, plant inlet volumes averaged 129,832 MMBtu/d and NGLs produced averaged 13,410 Bbls/d for plants owned by the Oklahoma segment. For the three months ended September 30, 2008, plant inlet volumes averaged 119,332 MMBtu/d and NGLs produced averaged 12,042 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2009, plant inlet volumes averaged 127,067 MMBtu/d and NGLs produced averaged 12,970 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2008, plant inlet volumes averaged 111,137 MMBtu/d and NGLs produced averaged 11,343 Bbls/d for plants owned by the Oklahoma segment.
- 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 537,099 MMBtu/d and NGLs produced averaged 17,653 Bbls/d for the three months ended September 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 586,243 MMBtu/d and NGLs produced averaged 16,177 Bbls/d for the three months ended September 30, 2008 for plants owned by the Texas segment. Plant inlet volumes averaged 537,382 MMBtu/d and NGLs produced averaged 16,504 Bbls/d for the nine months ended September 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 601,831 MMBtu/d and NGLs produced averaged 16,423 Bbls/d for the nine months ended September 30, 2008 for plants owned by the Texas segment.
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 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 and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income, for each of the periods indicated (in thousands).
Three Months Nine Months
Ended Ended
September 30, September 30,
---------------- ---------------
2009 2008 2009 2008
---- ---- ---- ----
Reconciliation of total
segment gross margin to
operating income:
Operating income $18,146 $23,867 $52,149 $86,897
Add: Operations and
maintenance
expenses 13,202 15,211 38,764 39,770
Depreciation and
amortization 14,575 12,700 41,071 36,929
General and
administrative
expenses 9,200 11,042 29,246 33,828
Taxes other
than income 836 723 2,349 2,193
Equity in earnings
from
unconsolidated
affiliates (2,529) (2,170) (6,112) (7,354)
------ ------ ------ ------
Total segment gross
margin $53,430 $61,373 $157,467 $192,263
======= ======= ======== ========
Reconciliation of EBITDA
and adjusted EBITDA
to net income:
Net income $3,729 $8,723 $15,672 $46,427
Add: Depreciation and
amortization(1) 14,628 12,755 41,628 37,092
Interest and other
financing costs 15,440 15,470 41,889 42,939
Provision for
income taxes 304 197 1,039 846
--- --- ----- ---
EBITDA 34,101 37,145 100,228 127,304
Add: Amortization of
difference between
the carried
investment and
the underlying
equity in net
assets of equity
investments 4,792 4,607 14,395 13,808
Copano's share of
depreciation and
amortization
included in
equity in earnings
from
unconsolidated
affiliates 1,707 1,266 5,040 3,854
% of equity
method investment
interest and
other financing
costs 615 471 1,093 1,697
--- --- ----- -----
Adjusted EBITDA $41,215 $43,489 $120,756 $146,663
======= ======= ======== ========
Reconciliation of EBITDA
and adjusted EBITDA to
cash flows from operating
activities:
Cash flow provided by
operating activities $21,121 $23,236 $100,749 $101,221
Add: Cash paid
for interest
and other
financing costs 14,545 14,537 38,829 40,387
Equity in
earnings from
unconsolidated
affiliates 2,529 2,170 6,112 7,354
Distributions
from
unconsolidated
affiliates (6,894) (6,669) (18,333) (18,387)
Risk management
activities (4,983) (11,999) (23,462) 16,466
Increase
(decrease) in
working capital
and other 7,783 15,870 (3,667) (19,737)
----- ------ ------- --------
EBITDA 34,101 37,145 100,228 127,304
Add: Amortization of
difference
between the
carried investment
and the underlying
equity in net
assets of equity
investments 4,792 4,607 14,395 13,808
Copano's share of
depreciation and
amortization
included in
equity in
earnings from
unconsolidated
affiliates 1,707 1,266 5,040 3,854
% of equity
method
investment
interest and
other financing
costs 615 471 1,093 1,697
--- --- ----- -----
Adjusted EBITDA $41,215 $43,489 $120,756 $146,663
======= ======= ======== ========
Reconciliation of net
income to total
distributable cash flow:
Net income $3,729 $8,723 $15,672 $46,427
Add: Depreciation and
amortization(1) 14,628 12,755 41,628 37,092
Amortization of
commodity
derivative
options 9,236 8,425 27,715 24,482
Amortization of
debt issue costs 895 933 3,060 2,552
Equity-based
compensation 2,345 3,285 6,600 5,277
Distributions
from
unconsolidated
affiliates 7,297 7,763 21,524 20,358
Unrealized (gain)
loss associated
with line fill
contributions
and gas
imbalances (556) 2,117 (29) (490)
Unrealized loss
(gain) on
derivative
activity 194 (516) (1,442) 9,485
Deferred taxes
and other 68 (6) 740 161
Less: Equity in
earnings from
unconsolidated
affiliates (2,529) (2,170) (6,112) (7,354)
Maintenance
capital
expenditures (1,886) (2,675) (7,932) (8,828)
------- ------ ------ ------
Total distributable
cash flow(2) $33,421 $38,634 $101,424 $129,162
======= ======= ======== ========
Actual quarterly
distribution ("AQD") $31,855 $27,969
======= =======
Total distributable
cash flow coverage
of AQD 105% 138%
==== ====
(1) Depreciation and amortization includes depreciation and amortization
related to discontinued operations.
(2) Prior to any retained cash reserves established by Copano's Board of
Directors.
SOURCE Copano Energy, L.L.C.
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