Exhibit 99.1
		News Release
Copano Energy, L.L.C.
	Contacts:		Carl A. Luna, Senior Vice President and CFO
			Copano Energy, L.L.C.
FOR IMMEDIATE RELEASE			713-621-9547
			Jack Lascar / jlascar@drg-e.com
			Anne Pearson/ apearson@drg-e.com
			DRG&E / 713-529-6600

COPANO ENERGY REPORTS FOURTH QUARTER

AND YEAR END 2009 RESULTS

    HOUSTON, February 25, 2010 — Copano Energy, L.L.C. (NASDAQ:  CPNO) today announced its financial results for the three months and year ended December 31, 2009.

“We are pleased with the improvements in the results of our operating segments for the fourth quarter,” said R. Bruce Northcutt, Copano Energy’s President and Chief Executive Officer.  “Our total distributable cash flow continues to improve from the 2009 low and includes larger contributions from our operating assets and less from our hedging activities as commodity prices have improved during the year.  We remain encouraged by our expansion projects in north and south Texas as a result of increased producer activity around our assets and expect these projects to provide growth in our distributable cash flow in 2010,” Northcutt said.

Fourth Quarter Financial Results

Revenue for the fourth quarter of 2009 increased 1% to $249.3 million compared with $246.9 million for the fourth quarter of 2008.  Total segment gross margin was $62.0 million for the fourth quarter of 2009 compared to $61.9 million for the same period a year ago.

Adjusted EBITDA for the fourth quarter of 2009 decreased 21% to $46.6 million compared with $59.2 million for the fourth quarter of 2008 primarily as a result of recognizing a $15.3 million gain in the fourth quarter of 2008 related to the repurchase and retirement of senior unsecured notes whereas no gain was recognized on the repurchase of debt in the fourth quarter of 2009.  Noncash charges for the fourth quarter of 2009 and 2008 that were not added back in determining adjusted EBITDA totaled $9.2 million and $8.4 million, respectively, and related to the noncash amortization expense of the option component of Copano’s risk management portfolio.

Total distributable cash flow for the fourth quarter of 2009 decreased to $35.0 million from $49.7 million for the fourth quarter of 2008, primarily because the fourth quarter 2009 results did not

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include a $15.3 million gain related to the retirement of debt.  Fourth quarter 2009 total distributable cash flow represents 110% coverage of the fourth quarter 2009 distribution of $0.575 per unit based on total common units outstanding on the record date for the distribution.

Net income for the fourth quarter of 2009 decreased by 21% to $9.3 million, or $0.16 per unit on a diluted basis, compared to net income of $11.8 million, or $0.21 per unit on a diluted basis, for the fourth quarter of 2008.  The drivers of Copano’s net income for the fourth quarter of 2009 compared to the fourth quarter of 2008 included:

·   a decrease of $15.3 million related to the gain on the retirement of debt in 2008; and

·   an increase in taxes other than income of $0.5 million;

partially offset by:

·   an increase in total segment gross margin of $0.1 million consisting of a $20.8 million increase in combined operating segment gross margins primarily reflecting an average NGL price increase of 49% on the Conway index and 20% on the Mt. Belvieu index slightly offset by lower overall service throughput volumes and a decrease of $20.7 million from Copano’s commodity risk management activities;

·   a decrease in operations and maintenance expenses of $1.3 million and general and administrative expenses of $1.5 million primarily related to reduced bad debt expense and the successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees;

·   an increase of $0.8 million in equity in earnings of unconsolidated affiliates;

·   a decrease in interest and other financing costs of $8.1 million primarily related to (i) a noncash mark-to-market gain on interest rate swaps for 2009 of $1.2 million compared to a $6.3 million loss in 2008, a change of $7.5 million and (ii) reduced amortization expense related to debt issuance costs of $1.0 million, offset by an increase of $0.4 million in interest paid as a result of increased average outstanding borrowings which was offset by lower average interest rates between the periods;

·   a decrease in income taxes of $0.7 million; and

·   an increase in income from discontinued operations of $0.8 million as a result of the sale of Copano’s crude oil pipeline operations.

Weighted average diluted units outstanding increased approximately 2% to 58.2 million for the fourth quarter of 2009 as compared with approximately 57.3 million for the same period in 2008.

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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.

Fourth Quarter Operating Results by Segment

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

Oklahoma

Segment gross margin for Oklahoma increased 47% in the fourth quarter of 2009 to $26.6 million, compared to $18.1 million for the fourth quarter of 2008.  The increase resulted primarily from a 55% increase in realized margins on service throughput from the fourth quarter of 2008 ($1.16 per MMBtu in 2009 compared with $0.75 per MMBtu in 2008), reflecting higher NGL, oil and natural gas prices.  During the fourth quarter of 2009, NGL prices based on Conway index prices and Copano’s weighted average product mix averaged $40.86 per barrel compared with $27.36 per barrel during the fourth quarter of 2008, an increase of $13.50, or 49%.  During the fourth quarter of 2009, natural gas prices based on CenterPoint East index prices averaged $4.01 per MMBtu compared with $3.58 per MMBtu during the fourth quarter of 2008, an increase of $0.43, or 12%.

In addition to higher realized prices, the increase in segment gross margin for Oklahoma also was impacted by increased NGL production, partially offset by decreased service throughput volumes.  The Oklahoma segment gathered an average of 250,248 MMBtu/d of natural gas, processed an average of 159,713 MMBtu/d of natural gas and produced an average of 16,123 Bbls/d of NGLs at its plants and third-party plants during the fourth quarter of 2009.  In comparison to the fourth quarter of 2008, this represents a 4% decrease in service throughput and a 6% increase in NGLs produced while plant inlet volumes were flat.  The decrease in service throughput is primarily attributable to reduced drilling, normal production declines and delayed down-hole repair schedules during 2009.  Although plant inlet volumes remained flat, the increase in NGL production in 2009 resulted from reduced periods of ethane rejection compared to the fourth quarter of 2008.  During the fourth quarter of 2008, the Oklahoma segment gathered an average of 261,107 MMBtu/d of natural gas, processed an average of 160,074 MMBtu/d of natural gas, produced an average of 15,253 Bbls/d of NGLs and operated in ethane rejection mode for 41 days.

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Texas

Segment gross margin for Texas increased approximately 70% in the fourth quarter of 2009 to $32.8 million, compared to $19.3 million for the fourth quarter of 2008.  The increase resulted primarily from a 94% increase in realized margins on service throughput from the fourth quarter of 2008 ($0.60 per MMBtu in 2009 compared with $0.31 per MMBtu in 2008), reflecting higher NGL and oil prices.  During the fourth quarter of 2009, NGL prices based on Mt. Belvieu index prices and Copano’s weighted average product mix averaged $42.96 per barrel compared with $35.70 per barrel during the fourth quarter of 2008, an increase of $7.26, or 20%.  During the fourth quarter of 2009, natural gas prices based on Houston Ship Channel index prices averaged $4.16 per MMBtu compared with $6.37 per MMBtu during the fourth quarter of 2008, a decrease of $2.21, or 35%.

The increase in segment gross margin for the Texas segment was offset by decreased service throughput and processing volumes.  During the fourth quarter of 2009, the Texas segment provided gathering, transportation and processing services for an average of 576,224 MMBtu/d of natural gas compared with 679,142 MMBtu/d for the fourth quarter of 2008, a decrease of 15%.  The Texas segment gathered an average of 271,061 MMBtu/d of natural gas, processed an average of 497,368 MMBtu/d of natural gas at its plants and third-party plants and produced an average of 18,292 Bbls/d of NGLs at its plants and third-party plants during the fourth quarter of 2009, representing decreases of 13% of volumes gathered and 17% of volumes processed, and an increase of 65% of NGLs produced as compared with the fourth quarter of 2008.  The increase in NGL production was primarily the result of additional volumes processed at Copano’s Saint Jo plant in north Texas beginning in the second quarter of 2009, reduced periods of conditioning and ethane rejection compared to the fourth quarter of 2008 and an increase in NGL production at Copano’s Lake Charles plant.  During the fourth quarter of 2008, the Texas segment gathered an average of 312,753 MMBtu/d of natural gas, processed an average of 600,719 MMBtu/d of natural gas, produced an average of 11,116 Bbls/d of NGLs and operated in ethane rejection or conditioning mode for 56 days.  Volumes originating from the Texas segment and delivered to the Houston Central plant decreased approximately 15% from the fourth quarter of 2008 while natural gas delivered to the Houston Central plant and originating from sources other than the Texas segment decreased approximately 22% from the fourth quarter of 2008.

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Rocky Mountains

 Segment gross margin for Rocky Mountains decreased approximately 54% in the fourth quarter of 2009 to $1.1 million, compared with $2.4 million for the fourth quarter of 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), averaged 157,896 MMBtu/d for the fourth quarter of 2009, as compared to 196,233 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 decreased 3% in the fourth quarter of 2009 as compared with the fourth quarter of 2008 as a result of the items discussed above.  Average combined pipeline throughput for Bighorn and Fort Union for the fourth quarter of 2009 and 2008 totaled 965,033 MMBtu/d and 998,239 MMBtu/d, respectively.  Additionally, the Rocky Mountains segment gross margin includes fee revenue from compressors Copano began leasing to Bighorn early in 2009.

Corporate and Other

Corporate and other gross margin includes Copano’s commodity risk management activities.  These activities produced a gain of $1.4 million for the fourth quarter of 2009 compared to a gain of $22.1 million for the fourth quarter of 2008.  The gain for the fourth quarter of 2009 included $6.4 million of net cash settlements received for expired commodity derivative instruments and $4.2 million of unrealized mark-to-market gains on undesignated economic hedges, offset by $9.2 million of noncash amortization expense relating to the option component of Copano’s risk management portfolio.  The fourth quarter 2008 gain included $27.5 million of net cash settlements received for expired commodity derivative instruments and $3.0 million of unrealized mark-to-market gains on undesignated economic hedges, offset by $8.4 million of noncash amortization expense relating to the option component of Copano’s risk management portfolio.

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Year-to-Date Financial Results

Revenue for 2009 decreased 45% to $820.0 million compared to $1.5 billion for 2008.  Total segment gross margin decreased 14% to $219.5 million for 2009 from $254.1 million for 2008.  For 2009, total segment gross margin included a net gain of $35.9 million related to Copano’s risk management activities, consisting of $68.7 million of net cash settlements received on expired commodity derivative instruments and $4.1 million of unrealized mark-to-market gains on undesignated economic hedges, offset by $36.9 million of noncash amortization expense relating to the option component of Copano’s risk management portfolio.  Total segment gross margin for 2008 included a net loss of $27.6 million related to Copano’s risk management activities, consisting of $32.8 million of noncash amortization expense relating to the option component of Copano’s risk management portfolio and $2.8 million of unrealized mark-to-market losses on undesignated economic hedges, offset by $8.0 million of net cash settlements received on expired commodity derivative instruments.

 Adjusted EBITDA decreased 19% to $167.4 million for 2009 compared to $205.8 million for 2008.  Total distributable cash flow decreased 24% to $136.5 million for 2009 compared to $178.9 million for 2008.  Approximately $11.3 million of the decrease in adjusted EBITDA and total distributable cash flow was attributable to the lower gain on the retirement of debt in 2009.

Net income decreased by 57% to $25.0 million, or $0.43 per unit on a diluted basis, for 2009 compared to net income of $58.2 million, or $1.01 per unit on a diluted basis, for 2008.  The drivers of net income for 2009 compared to 2008 included:

·   a decrease in total segment gross margin of $34.7 million, consisting of a $98.2 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 42% in the Conway index and 45% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $63.5 million from commodity risk management activities;

·   an increase in depreciation, amortization and impairment expenses of $4.1 million primarily related to expanded operations in north Texas;

·   a decrease of $11.3 million attributable to the reduction of gain on the retirement of debt in 2009;

·   an increase in taxes other than income of $0.7 million; and

·   a decrease of $0.4 million in equity in earnings of unconsolidated affiliates;

partially offset by:

·   a decrease in general and administrative expenses of $6.1 million and operations and maintenance expenses of $2.3 million primarily related to reduced bad debt expense and

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·   successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees;

·   a decrease of $9.2 million in interest expense primarily related to (i) a noncash mark-to-market gain on interest rate swaps for 2009 of $2.8 million compared to a $10.0 million loss in 2008, a change of $12.8 million and (ii) reduced amortization expense related to debt issuance costs of $0.6 million, offset by an increase in interest paid of $4.2 million as a result of increased average outstanding borrowings which was offset by lower average interest rates between the periods; and

·   a decrease in income taxes of $0.4 million.

Cash Distributions

On January 13, 2010, Copano announced its fourth 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 unchanged from the third quarter of 2009 and was paid on February 11, 2010 to common unitholders of record at the close of business on February 1, 2010.

Conference Call Information

Copano will hold a conference call to discuss its fourth quarter 2009 financial results and recent developments on Friday, February 26, 2010 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time).  To participate in the call, dial (480) 629-9722 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 March 5, 2010 by calling (303) 590-3030 and using the pass code 4216091#.

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.

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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 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

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·   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 noncash 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 Copano generates  (prior to the establishment of any retained cash reserves by its Board of Directors) to the cash distributions Copano expects to pay its unitholders.  Copano’s Compensation Committee and Board of Directors have designated total distributable cash flow per common unit as the financial objective under Copano’s Management Incentive Compensation Plan.  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

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analysts with respect to publicly traded partnerships and limited liability companies because the market value of such 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.  Its assets include approximately 6,200 miles of active natural gas gathering and transmission pipelines, 200 miles of NGL pipelines and seven natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity.  For more information, please visit www.copanoenergy.com.

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.

– financial statements to follow –

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended December 31,						Year Ended December 31,
	2009			2008			2009			2008
	(In thousands, except per unit information)
Revenue:
Natural gas sales	$	90,443		$	127,184		$	316,686		$	747,258
Natural gas liquids sales		135,270			90,007			406,662			597,986
Transportation, compression and processing fees		13,145			16,110			55,983			59,006
Condensate and other		10,396			13,587			40,715			50,169
Total revenue		249,254			246,888			820,046			1,454,419
Costs and expenses:
Cost of natural gas and natural gas liquids (1)		181,334			178,724			576,448			1,178,304
Transportation (1)		5,937			6,283			24,148			21,971
Operations and maintenance		12,713			14,054			51,477			53,824
Depreciation, amortization and impairment		15,904			15,987			56,975			52,916
General and administrative		10,265			11,743			39,511			45,571
Taxes other than income		1,383			826			3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates		(297	)		465			(6,409	)		(6,889	)
Total costs and expenses		227,239			228,082			745,882			1,348,716
Operating income		22,015			18,806			74,164			105,703
Interest and other income		83			83			1,202			1,174
Gain on retirement of unsecured debt		—			15,272			3,939			15,272
Interest and other financing costs		(13,947	)		(22,039	)		(55,836	)		(64,978	)
Income before income taxes		8,151			12,122			23,469			57,171
Provision for income taxes		245			(403	)		(794	)		(1,249	)
Income from continuing operations		8,396			11,719			22,675			55,922
Discontinued operations, net of tax		899			67			2,292			2,291
Net income	$	9,295		$	11,786		$	24,967		$	58,213
Basic net income per common unit:
Income per common unit from continuing operations	$	0.15		$	0.23		$	0.42		$	1.15
Income per common unit from discontinued operations		0.02			0.00			0.04			0.05
Net income per common unit	$	0.17		$	0.23		$	0.46		$	1.20
Weighted average number of common units		54,601			51,112			54,395			48,513
Diluted net income per common unit:
Income per common unit from continuing operations	$	0.14		$	0.21		$	0.39		$	0.97
Income per common unit from discontinued operations		0.02			0.00			0.04			0.04
Net income per common unit	$	0.16		$	0.21		$	0.43		$	1.01
Weighted average number of common units		58,192			57,276			58,038			57,856
(1) Exclusive of operations and maintenance and depreciation, amortization and impairment shown separately below.

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Year Ended December 31,
	2009			2008
	(In thousands)
Cash Flows From Operating Activities:
Net income	$	24,967		$	58,213
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		57,539			50,314
Impairment of goodwill		—			2,840
Amortization of debt issue costs		3,955			4,467
Equity in earnings from unconsolidated affiliates		(6,409	)		(6,889	)
Distributions from unconsolidated affiliates		22,740			22,460
Gain on retirement of unsecured debt		(3,939	)		(15,272	)
Noncash (gain) loss on risk management portfolio, net		(6,879	)		12,751
Equity-based compensation		8,455			5,858
Deferred tax provision		144			486
Other noncash items		(816	)		98
Changes in assets and liabilities:
Accounts receivable		5,545			32,090
Prepayments and other current assets		67			(1,123	)
Risk management activities		30,155			(27,037	)
Accounts payable		8,764			(44,766	)
Other current liabilities		(1,161	)		(4,566	)
Net cash provided by operating activities		143,127			89,924
Cash Flows From Investing Activities:
Additions to property, plant and equipment		(73,232	)		(152,533	)
Additions to intangible assets		(3,060	)		(9,189	)
Acquisitions		(2,840	)		(12,655	)
Investment in unconsolidated affiliates		(4,228	)		(26,832	)
Distributions from unconsolidated affiliates		6,944			3,370
Escrow cash		—			(1,858	)
Proceeds from the sale of assets		6,061			28
Other		(2,421	)		814
Net cash used in investing activities		(72,776	)		(198,855	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		70,000			579,000
Repayment of long-term debt		(20,000	)		(339,000	)
Retirement of unsecured debt		(14,286	)		(34,313	)
Deferred financing costs		—			(6,688	)
Distributions to unitholders		(125,721	)		(104,234	)
Capital contributions from pre-IPO investors		—			4,103
Equity offering costs		—			(47	)
Proceeds from option exercises		664			1,129
Net cash (used in) provided by financing activities		(89,343	)		99,950
Net decrease in cash and cash equivalents		(18,992	)		(8,981	)
Cash and cash equivalents, beginning of year		63,684			72,665
Cash and cash equivalents, end of year	$	44,692		$	63,684

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	As of December 31,
	2009			2008
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$	44,692		$	63,684
Accounts receivable, net		91,156			96,028
Risk management assets		36,615			76,440
Prepayments and other current assets		4,937			4,891
Discontinued operations		—			5,564
Total current assets		177,400			246,607
Property, plant and equipment, net		841,323			819,099
Intangible assets, net		190,376			198,341
Investment in unconsolidated affiliates		620,312			640,598
Escrow cash		1,858			1,858
Risk management assets		15,381			82,892
Other assets, net		22,571			24,270
Total assets	$	1,869,221		$	2,013,665
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	111,021		$	103,849
Accrued interest		11,921			11,904
Accrued tax liability		672			784
Risk management liabilities		9,671			6,272
Other current liabilities		9,358			16,787
Total current liabilities		142,643			139,596
Long-term debt (includes $628 and $704 bond premium as of December 31, 2009 and 2008, respectively)		852,818			821,119
Deferred tax provision		1,862			1,718
Risk management and other noncurrent liabilities		10,063			13,274
Members’ capital:
Common units, no par value, 54,670,029 and 53,965,288 units issued and outstanding as of December 31, 2009 and 2008, respectively		879,504			865,343
Class C units, no par value, 0 units and 394,853 units issued and outstanding as of December 31, 2009 and 2008, respectively		—			13,497
Class D units, no par value, 3,245,817 units issued and outstanding as of December 31, 2009 and 2008		112,454			112,454
Paid-in capital		42,518			33,734
Accumulated deficit		(156,458	)		(54,696	)
Accumulated other comprehensive (loss) income		(16,183	)		67,626
		861,835			1,037,958
Total liabilities and members’ capital	$	1,869,221		$	2,013,665

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

OPERATING STATISTICS

(Unaudited)

	Three Months Ended December 31,						Year Ended December 31,
	2009			2008			2009			2008
	($ in thousands)
Total segment gross margin(1) (2)	$	61,983		$	61,881		$	219,450		$	254,144
Operations and maintenance expenses(2)		12,713			14,054			51,477			53,824
Depreciation and amortization(2)		15,904			15,987			56,975			52,916
General and administrative expenses		10,265			11,743			39,511			45,571
Taxes other than income		1,383			826			3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates		(297	)		465			(6,409	)		(6,889	)
Operating income(2)		22,015			18,806			74,164			105,703
Gain on retirement of unsecured debt		—			15,272			3,939			15,272
Interest and other financing costs, net		(13,864	)		(21,956	)		(54,634	)		(63,804	)
Provision for income taxes		245			(403	)		(794	)		(1,249	)
Discontinued operations, net of tax		899			67			2,292			2,291
Net income	$	9,295		$	11,786		$	24,967		$	58,213
Total segment gross margin:
Oklahoma(2)	$	26,628		$	18,060		$	76,686		$	133,112
Texas		32,845			19,256			103,620			142,723
Rocky Mountains		1,110			2,439			3,254			5,877
Segment gross margin(2)		60,583			39,755			183,560			281,712
Corporate and other(3)		1,400			22,126			35,890			(27,568	)
Total segment gross margin(1) (2)	$	61,983		$	61,881		$	219,450		$	254,144
Segment gross margin per unit:
Oklahoma:
Service throughput ($/MMBtu) (2) (4)	$	1.16		$	0.75		$	0.80		$	1.52
Texas:
Service throughput ($/MMBtu) (5)	$	0.60		$	0.31		$	0.46		$	0.57
Rocky Mountains:
Producer services throughput ($/MMBtu) (6)	$	0.03		$	0.06		$	0.04		$	0.06
Volumes:
Oklahoma:(4) (7)
Service throughput (MMBtu/d)		250,248			261,107			262,259			238,836
Plant inlet throughput (MMBtu/d)		159,713			160,074			163,474			156,057
NGLs produced (Bbls/d)		16,123			15,253			15,977			15,126
Texas: (5) (8)
Service throughput (MMBtu/d)		576,224			679,142			619,615			686,791
Pipeline throughput (MMBtu/d)		271,061			312,753			290,627			314,252
Plant inlet volumes (MMBtu/d)		497,368			600,719			539,633			610,249
NGLs produced (Bbls/d)		18,292			11,116			17,959			16,150
Rocky Mountains:
Producer services throughput (MMBtu/d)(6)		157,896			196,233			165,579			220,792
Capital Expenditures:
Maintenance capital expenditures	$	1,796		$	2,941		$	9,728		$	11,769
Expansion capital expenditures		19,305			40,463			61,424			169,056
Total capital expenditures	$	21,101		$	43,404		$	71,152		$	180,825
Operations and maintenance expenses:
Oklahoma(2)	$	6,134		$	6,014		$	23,469		$	23,874
Texas		6,537			8,040			27,960			29,950
Rocky Mountains		42			—			48			—
Total operations and maintenance expenses	$	12,713		$	14,054		$	51,477		$	53,824

[Missing Graphic Reference]

(1) 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 of operating income, please read “Non-GAAP Financial Measures.”

(2) Excludes results attributable to Copano’s crude oil pipeline and related assets as these amounts are shown under the caption “Discontinued operations.”

(3) Corporate and other includes results attributable to Copano’s commodity risk management activities.

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(4) Excludes volumes associated with Copano’s interest in Southern Dome.  For the three months ended December 31, 2009, plant inlet volumes for Southern Dome averaged 12,639 MMBtu/d and NGLs produced averaged 444 Bbls/d.  For the three months ended December 31, 2008, plant inlet volumes for Southern Dome averaged 8,195 MMBtu/d and NGLs produced averaged 295 Bbls/d.  For the year ended December 31, 2009, plant inlet volumes for Southern Dome averaged 13,137 MMBtu/d and NGLs produced averaged 478 Bbls/d.  For the year ended December 31, 2008, plant inlet volumes for Southern Dome averaged 9,923 MMBtu/d and NGLs produced averaged 364 Bbls/d.

(5) Excludes volumes associated with Copano’s interest in Webb Duval.  Gross volumes transported by Webb Duval, net of intercompany volumes, were 66,764 MMBtu/d and 92,222 MMBtu/d for the three months ended December 31, 2009 and 2008, respectively.  Gross volumes transported by Webb Duval, net of intercompany volumes, were 78,160 MMBtu/d and 91,342 MMBtu/d for the year ended December 31, 2009 and 2008, respectively.

(6) 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.  Combined volumes gathered by Bighorn and Fort Union were 965,033 MMBtu/d and 998,239 MMBtu/d for the three months ended December 31, 2009 and 2008, respectively.  Combined volumes gathered by Bighorn and Fort Union were 975,785 MMBtu/d and 945,925 MMBtu/d for the year ended December 31, 2009 and 2008, respectively.

(7) 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 December 31, 2009, plant inlet volumes averaged 125,914 MMBtu/d and NGLs produced averaged 13,261 Bbls/d for plants owned by the Oklahoma segment.  For the three months ended December 31, 2008, plant inlet volumes averaged 123,091 MMBtu/d and NGLs produced averaged 12,245 Bbls/d for plants owned by the Oklahoma segment.  For the year ended December 31, 2009, plant inlet volumes averaged 126,776 MMBtu/d and NGLs produced averaged 13,044 Bbls/d for plants owned by the Oklahoma segment.  For the year ended December 31, 2008, plant inlet volumes averaged 114,142 MMBtu/d and NGLs produced averaged 11,570 Bbls/d for plants owned by the Oklahoma segment.

(8) 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 489,894 MMBtu/d and NGLs produced averaged 17,718 Bbls/d for the three months ended December 31, 2009 for plants owned by the Texas segment.  Plant inlet volumes averaged 581,147 MMBtu/d and NGLs produced averaged 9,688 Bbls/d for the three months ended December 31, 2008 for plants owned by the Texas segment.  Plant inlet volumes averaged 525,413 MMBtu/d and NGLs produced averaged 16,810 Bbls/d for the year ended December 31, 2009 for plants owned by the Texas segment.  Plant inlet volumes averaged 596,535 MMBtu/d and NGLs produced averaged 14,715 Bbls/d for the year ended December 31, 2008 for plants owned by the Texas segment.

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Non-GAAP Financial Measures

The following table presents a reconciliation of the non-GAAP financial measures of (i) total [Missing Graphic Reference]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 Ended December 31,						Year Ended December 31,
		2009			2008			2009			2008
Reconciliation of total segment gross margin to operating income:
Operating income		$	22,015		$	18,806		$	74,164		$	105,703
Add:     Operations and maintenance expenses			12,713			14,054			51,477			53,824
Depreciation, amortization and impairment			15,904			15,987			56,975			52,916
General and administrative expenses			10,265			11,743			39,511			45,571
Taxes other than income			1,383			826			3,732			3,019
Equity in (earnings) loss from unconsolidated affiliates			(297	)		465			(6,409	)		(6,889	)
Total segment gross margin		$	61,983		$	61,881		$	219,450		$	254,144
Reconciliation of EBITDA and adjusted EBITDA to net income:
Net income		$	9,295		$	11,786		$	24,967		$	58,213
Add:     Depreciation, amortization and impairment(1)			15,911			16,062			57,539			53,154
Interest and other financing costs			13,947			22,039			55,836			64,978
Provision for income taxes			(245	)		403			794			1,249
EBITDA			38,908			50,290			139,136			177,594
Add:  Amortization of difference between the carried investment and the underlying equity in net assets of equity investments			4,808			5,308			19,203			19,116
Copano’s share of depreciation and amortization included in equity in earnings (loss) from unconsolidated affiliates			2,687			2,009			7,727			5,863
Copano’s share of interest and other financing costs incurred by equity method investment			210			1,562			1,303			3,259
Adjusted EBITDA		$	46,613		$	59,169		$	167,369		$	205,832
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
Cash flow provided by operating activities		$	42,378		$	(11,297	)	$	143,127		$	89,924
Add:   Cash paid for interest and other financing costs			13,052			20,123			51,881			60,510
Equity in earnings (loss) from unconsolidated affiliates			297			(465	)		6,409			6,889
Distributions from unconsolidated affiliates			(4,407	)		(4,073	)		(22,740	)		(22,460	)
Risk management activities			(6,693	)		(8,360	)		(30,155	)		27,037
Changes in working capital and other			(5,719	)		54,362			(9,386	)		15,694
EBITDA			38,908			50,290			139,136			177,594
Add:  Amortization of difference between the carried investment and the underlying equity in net assets of equity investments			4,808			5,308			19,203			19,116
Copano’s share of depreciation and amortization included in equity in earnings (loss) from unconsolidated affiliates			2,687			2,009			7,727			5,863
Copano’s share of interest and other financing costs incurred by equity method investment			210			1,562			1,303			3,259
Adjusted EBITDA		$	46,613		$	59,169		$	167,369		$	205,832
Reconciliation of net income to total distributable cash flow:
Net income		$	9,295		$	11,786		$	24,967		$	58,213
Add:  Depreciation, amortization and impairment(1)			15,911			16,062			57,539			53,154
Amortization of commodity derivative options			9,235			8,360			36,950			32,842
Amortization of debt issue costs			895			1,915			3,955			4,467
Equity-based compensation			1,652			2,512			8,252			7,789
Distributions from unconsolidated affiliates			8,160			5,472			29,684			25,830
Unrealized (gain) loss associated with line fill contributions and gas imbalances			(2,116	)		1,082			(2,145	)		592
Unrealized (gain) loss on derivative activity			(5,437	)		3,266			(6,879	)		12,751
Deferred taxes and other			(469	)		1,766			271			1,927
Less:  Equity in (earnings) loss from unconsolidated affiliates			(297	)		465			(6,409	)		(6,889	)
Maintenance capital expenditures			(1,796	)		(2,941	)		(9,728	)		(11,769	)
Total distributable cash flow(2)		$	35,033		$	49,745		$	136,457		$	178,907
Actual quarterly distribution (“AQD”)		$	31,911		$	31,466
Total distributable cash flow coverage of AQD			110	%		158	%
________________________
(1)	Includes depreciation and amortization related to discontinued operations.
(2)	Prior to any retained cash reserves established by Copano’s Board of Directors.

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